workover planning

7/25/2019 Workover Planning

1/30

CM 19

COMPLETION WORKOVER PLANNING Page 1 of 29

MANUAL Issue 1PROPRIETARY INFORMATION -For Authorised Company Use Only January 1998

DRILLING DEPARTMENT

PETRONAS CARIGALI SDN BHD

CHAPTER 19

WORKOVER PLANNING

TABLE OF CONTENTS

19.1 INTRODUCTION . 3

19.1.1

19.1.2

What Is A Workover?

.

Planning A Workover

.

3

3

19.2 WELL PROBLEMS REQUIRING WORKOVERS .. 4

19.2.1

19.2.2

19.2.3

19.2.4

19.2.519.2.6

19.2.7

19.2.8

19.2.9

19.2.10

19.2.11

Low Reservoir Pressure

..

Low Reservoir Permeability ...

Formation Damage

..Wellbore Restrictions

..

High Viscosity Oil ..

Improper Equipment Sizing/Operation ...

Excessive Water Production

Excessive Gas Production

...

Mechanical Failures

Primary Cement Failures

Non-Problem Wells

.

4

6

6

7

7 7

8

9

10

10

11

19.3 WELL ASSESSMENT DETERMINING THE PROBLEM . 12

19.3.1

19.3.2

Well And Completion Characteristics .

Well History

12

13


2/30

CM 19



DRILLING DEPARTMENT


19.3.319.3.4

19.3.5

Offset Well Performance

.

Cross Sections, Maps, Cores And Logs

..

Diagnostic Procedures

.

1414

15

19.4 ALTERNATIVE OPERATIONS AND TECHNIQUES .. 16

19.4.1

19.4.2

19.4.3

19.4.4

19.4.5

19.4.6

19.4.719.4.8

Types Of Workover Operations

..

Bullhead Technique

.

Wireline Workover Techniques ..

Concentric Workover Techniques

...Conventional Workover Techniques ...

Auxiliary Equipment ...

Support

Services

Other Considerations

...

16

18

18

18

19

20

2121

19.5 EVALUATING AND SELECTING A TECHNIQUE .... 23

19.5.1

19.5.219.5.3

Economic Analysis

..Capabilities/Limitations ..

Other Considerations

...

23

2424

19.6 JOB EXECUTION AND FOLLOW-UP .... 25


3/30

CM 19



DRILLING DEPARTMENT


19.6.119.6.2

19.6.3

19.6.4

Workover Procedure

Field

Operations

Analysis of Results...

Record Keeping

...

2526

26

26

19.7 WELL ANALYSIS CHECKLIST ...... 27

19.7.119.7.2

19.7.3

19.7.4

19.7.5

Well Completion Characteristics Well History


.

Cross Sections, Maps, Cores and Logs

...

Diagnostic Procedures

.

2727

27

28

28

19.8

REFERENCES....... 29

19.1 INTRODUCTION

This Chapter provides guidelines regarding assessment of well problems, choice of workover

operations for particular well problems, choice of workover techniques for particular

operations, evaluation of alternative techniques, and implementation of workover operations

in the field.

19.1.1 What Is Workover?

During the life of a well, problems such as decreased producing rate, increased water or gas

production, and mechanical failure may occur. After the initial completion, any work done


4/30

CM 19



DRILLING DEPARTMENT


on the well that affects the mechanical integrity or flow performance of the well is called aworkover.

19.1.2 Planning A Workover

When planning a workover operation for a well, the engineer should :

Identify the cause of the well problem.

Determine which types of workover operations will solve the problem.

Determine which workover techniques and equipment are available to perform the

workover.

Evaluate the economics, advantages and limitations of alternative workover techniques.

Select the appropriate technique for the operation.

Implement a safe and efficient field operations.

Analyze, record, and file the workover procedures and results.

19.2 WELL PROBLEMS REQUIRING WORKOVERS

Workover operations are performed for many reasons. Workovers may be required in

problem wells to :

Increase a declining production or injection rate caused by low reservoir pressure, lowreservoir permeability, formation damage, wellbore restrictions, high viscosity oil,

improper equipment sizing, or inadequate artificial lift.

Reduce excessive water or gas production.

Repair mechanical failures.


5/30

CM 19



DRILLING DEPARTMENT


Repair primary cementing failures.

It may also be necessary to perform a workover on a non-problem well to :

Gain additional production by recompleting or stimulating a well.

Evaluate the well or reservoir.

Convert an existing well to an injection or disposal well.

Physical phenomena leading to these well problems and the most commonly used workover

solutions are briefly summarized below. Specific topics are discussed in more detail in other

sections of the text.

19.2.1 Low Reservoir Pressure

In the life of a well, the producing rate will decline as reservoir pressure declines. To

maintain a constant producing rate as reservoir pressure declines, the flowing bottom-hole

pressure must be reduced. The amount of pressure reduction required depends on the

productivity index (PI)of the well.

For example, with a reservoir pressure of 2000 psi, withdrawal of 400 barrels of fluid per day

from a well with a PI of 2 will require a flowing bottom-hole pressure of 1800 psi. If thereservoir pressure falls to 1000 psi, however, the flowing bottom-hole pressure must now be

drawn down to 800 psi to produce 400 barrels per day. This pressure may be too low to

allow the well to flow.

The reservoir drive mechanism has a direct bearing on how long reservoir pressure can

provide a high flowing bottom-hole pressure. As shown in Figure 1, water, gas-cap, and

dissolved-gas-drive producing mechanisms each exhibit distinct pressure behavior as the oil

in place is produced. Reservoir pressure in dissolved-gas-drive reservoirs drops rapidly and

continuously with withdrawals. Gas-cap and water-drive reservoirs are less of a problem

from a pressure maintenance standpoint.

From a workover standpoint, low reservoir pressure presents a difficult situation. Stimulation

is less effective than in a high-pressure reservoir because there is less pressure differential

to capitalize on the increased permeability. Perforating an additional interval is a temporary

measure, at best, and may complicate future workovers. Installation of artificial lift

equipment is often the only practical approach to increased production.


6/30

CM 19



DRILLING DEPARTMENT


Figure 1. Influence of producing mechanism on reservoir pressure

19.2.2 Low Reservoir Permeability

Once the fluids near the wellbore are produced, productivity in a reservoir of low naturalpermeability declines rapidly. Wells completed in very low permeability formations are

usually stimulated to increase reservoir permeability away from the near-wellbore region.

Unless formation damage is also present, matrix acidizing is not applicable in this type of

stimulation. A large-volume hydraulic fracturing treatment, designed to yield high

conductivity and maximum drainage area, is usually the most effective approach.


7/30

CM 19



DRILLING DEPARTMENT


Figure 2. Effect of damaged zone on productivity

19.2.3 Formation Damage

Limited productivity-in reality, low flowing bottom-hole pressure-is in many instances caused

by reduction in permeability around the wellbore. This localized damage is commonly

referred to as formation damage. As shown in Figure 2, any damage in the near-wellbore

region magnifies productivity decline by increasing the pressure drop into wellbore for a fixed

flow rate.

Repair of formation damage requires eliminating or bypassing the damaged zone. Acidizing,

solvent and surfactant treatment, and fracturing are the principal means of damage repair.

Types of formation damage and their diagnosis are discussed in Chapter 12, Formation

Damage.

19.2.4 Wellbore Restrictions


8/30

CM 19



DRILLING DEPARTMENT


Restrictions in the wellbore may be the result of sand, paraffin, scale, asphalt, or othermaterials that inhibit flow in the tubing, casing, or perforations.

If the casing or tubing is blocked with debris, washout operations using mechanical or

chemical treatments will often restore the well to full capacity. Once tubing, casing or

perforation blocks are diagnosed and removed, an evaluation should be made to see if further

remedial steps are required.

19.2.5 High Viscosity Oil

In a reservoir which contains low-gravity crude, productivity may decrease as reservoir

pressure declines and liberates the gas dissolved in the oil. To facilitate production, oil

mobility near the wellbore and in the drainage area should be maximized.

Oil mobility can be increased by heating the reservoir with steam injection or other thermal

processes. Heat reduces oil viscosity and thus stimulates production.

19.2.6 Improper Equipment Sizing/Operation

The equipment installed in the well may be too small to handle production of the desired

amount of fluid. This can include tubulars, artificial lift, and surface equipment. Equipment

should be sized so that wells are not tubing, pumping, or facilities limited. The only limitshould be the reservoirs ability to produce.

For example, as water encroaches into a reservoir, production of larger volumes of fluid is

necessary to yield the same amount of oil. Reevaluation of pressure-drop calculations for

tubular goods or review of sucker-rod pump capacities may result in equipment replacements

more closely tailored to the desired rate of production.

Improper design or malfunction of artificial lift equipment can also curtail the producing rate.

If the sucker-rod pump is set too high or is experiencing gas locking, the installation will need

to be modified. Likewise, a gas-lift valve may be open or inoperative, prohibiting maximum

drawdown.

19.2.7 Excessive Water Production

Water production problems can originate from the reservoir itself or from other sources such

as casing leaks and primary cement failures. Water production is costly from both lifting and

disposal standpoints. However, recovery from water-drive reservoirs requires a large influx

of water into the reservoir, which may eventually necessitate producing considerable

quantities of water from the reservoir before the economic limit for oil recovery is reached.


9/30

CM 19



DRILLING DEPARTMENT


Water production problems arising from reservoir properties include :

Water Encroachment Water encroachment is the rise (decrease in depth) of the

water-oil contact as a reservoir is depleted. Water encroachment is a normal

occurrence in water-drive reservoirs as the aquifer moves into the oil zone to replace

withdrawals. Excessive water production in this instance can usually be controlled by

squeeze cementing or plug-back methods.

Water Coning and Fingering High withdrawal rates from individual wells tend to

create abnormally low-pressure areas around the wells. If such wells are located low

on the structure and near the water level, water will tend to be drawn up across thebedding planes and into the well as a water cone (Figure 3) or be drawn up along the

bedding planes of a stratified sand as a water finger (Figure 4).

Figure 3. Representation of water coning


10/30

CM 19



DRILLING DEPARTMENT


Figure 4. Representation of water fingering

19.2.8 Excessive Gas Production

Gas production form an oil well result from a gas originally dissolved in the reservoir oil or

from free gas that has segregated and become trapped above the oil as a gas cap. Free gas

may also enter the wellbore from a gas zone separate from the oil reservoir through channels

in the primary cement or as a result of casing leaks.

Solution Gas In the dissolved-gas-drive reservoir, gas originally in the oil is liberated

from solution as oil production begins and reservoir pressure declines. Further liberation

and expansion of solution gas is requirement for primary oil recovery from a reservoir

of this type. As oil withdrawals continue, the increase in gas saturation permits gas to

be produced along with the oil. As production proceeds, the relative permeability of the

rock to oil diminishes rapidly, and gas becomes the predominant mobile fluid. High-ratio

gas production in this instance is usually not a well problem but a problem of the

reservoir as a whole. Workovers are not generally successful at reducing the gas-oil-

ratio for these wells.


11/30

CM 19



DRILLING DEPARTMENT


Gas Encroachment If the reservoir is being produced by a gas-cap drive, gasproduction may increase as the gas-oil contact advances into the oil column. Excessive

gas production in this instance may be remedied temporarily by lowering the perforated

interval, or by reducing the production rate.

19.2.9 Mechanical Failures

Mechanical failures requiring workovers include :

Casing leaks Casing leaks result in both influx of undesirable gas or water into the

wellbore and the uncontrolled loss of reservoir fluids to other zones. Since casing leaksare usually associated with corrosion, the permeability of their development increases

with lengthening well life.

Tubing collapse Collapse of tubulars may result in stuck tools down-hole, as well as

leaks and subsequent influx of undesirable fluids into the wellbore.

Surface and downhole equipment failures Mechanical failures are often

associated with installed well equipment such as tubing, packers, and artificial-lift. The

first indication of this type of failure is often an observation of unexpected pressures at

the surface.

When performing a workover to repair a mechanical failure, the engineer should study the

well files to determine if other problems exist, which can be repaired at the same time.

19.2.10 Primary Cement Failures

A poor primary cement job resulting in channels between the formation and the casing can

lead to :

Unwanted fluid production from water or gas in the zone of interest.

Unwanted production of water or gas from an adjacent zone.

Collapsed casing during operations in which high pressures are applied through the

perforations below a packer (squeeze cementing, hydraulic fracturing).

Repair of primary cementing failures is discussed in Chapter 21, Remedial Cementing.


12/30

CM 19



DRILLING DEPARTMENT


19.2.11 Non-Problem Wells

Although correction of problem wells constitutes a large part of any workover program,

there are other reasons for conducting workovers, including :

Recompletions Recompletions are performed to gain additional production in new

zones or to more effectively drain a developed reservoir. The usual procedure for this

type of workover is to squeeze cement and reperforate into a new zone or reservoir.

However, in other instances, the well could be abandoned either totally or partially then

whipstocked / sidetracked into a new zone from the existing wellbore. It may also be

necessary to deepen or plug back the well or to add additional tubulars and downholeequipment. Selection of the producing interval for the recompletions should be carefully

considered to prevent premature gas or water production and to minimize future

workovers. This subject is discussed further in Chapter 2, Types of Well

Completions.

Well Assessment During a workover, it may be necessary to assess the condition

of the well or to evaluate the reservoir. Operations to assess the well include

production logging and well testing. Production logging is discussed in Chapter 20.

Service Well Installation When producing wells are converted to water or gas

injection or to water disposal service, a workover must be performed to install the new

equipment such as pumps and filters. When wells are converted from production to

injection, tubing design calculations should be performed. The temperatures and

pressures experienced during injection may differ from those during production,

necessitating redesign of the completion.


13/30

CM 19



DRILLING DEPARTMENT


19.3 WELL ASSESSMENT DETERMINING THE PROBLEM

Prior to performing a workover, the well problem be analyzed to determine the cause of the

problem. It is important important to determine whether the problem is associated with

properties of the reservoir or with the well itself. A through pre-workover evaluation can

increase the cost effectiveness of the entire operation.

Well and Completion Characteristics

Well History


Geological Data, Maps and Cross Sections

Open-hole Logs and Core Data

Well Tests

Production Logs

Special Surveys

Each of these areas is discussed briefly below. A checklist, summarizing the factors to

consider in each area is included at the end of this Chapter (Subject 19.7).

19.3.1 Well and Completion Characteristics

The current condition of the well may limit the types operations that can be performed during

a workover. Factors to consider include :

The completion type and down-hole equipment in place may preclude the use of

certain workover operations or require additional procedures, such as pulling the tubing,

prior to performing the workover.

The pressure ratings of casing, tubing and wellhead equipment are critical to

operations that require application of pressure e.g., stimulation treatments, squeeze


14/30

CM 19



DRILLING DEPARTMENT


cementing, and sand control. Pressure ratings are also important if the well is beingrecompleted to a higher-pressure interval.

Reservoir characteristics such as pressure, sand consolidation, and susceptibility to

damage can influence the success of workover operations or at least dictate the use of

special procedures.

Properties of the fluid currently being produced, as well as any new fluids to be

produced as a result of the workover, must be known. These properties are important

because of the potential for hazards, such as H2S, which may require protective

equipment for personnel. In addition, the corrosivity of the fluid is critical in establishing

the quality and cost of equipment to be used in the workover.

Reservoir considerations such as recovery desired, type of drive mechanism,

relative structure position, current and allowable productivity, forecasted behavior, and

possible recovery by offset wells must be considered when planning the type of

workover operation to perform. These factors must be considered both for the current

producing zone(s) and for alternate or future producing zones.

19.3.2 Well History

The previous history of the well is important because it provides information regarding past

problems and can indicate operational limitations. Records should be researched sufficiently

to indicate whether a problem has existed before, and whether new, less expensive

techniques are available to correct the problem.

The field superintendent and other operations personnel should be consulted to determine if

any well behavior characteristics exist that have not been reported.

Factors to consider when evaluating the well history include :

Drilling Procedures What procedures were used to drill the well? Did the fluids

used cause or have the potential to cause formation damage? Were there indications of

lost returns?

Initial Completion When was the well completed? The age of the well gives

information regarding the likelihood of corroded casing, weak tubulars, or damaged

down-hole equipment.

What procedures were used to cement the well? Knowledge of cementing procedures,

problems encountered during cementing operations, and post-job cement evaluation will


15/30

CM 19



DRILLING DEPARTMENT


indicate non-cemented areas or channels in the cement sheath. If the integrity of thecement sheath is in question, a precautionary squeeze cement job may be advisable to

ensure that workover fluids are selectively placed in the zones to be treated.

Other questions to be answered include : How was the well completed initially? What

fluids were used during well completion procedures? How was the well perforated?

Production History The nature and reservoir pressure of produced fluids (both

current and past0 should be determined. The rates and ratios of gas-oil and water-oil

production, the dates water or gas production first appeared, changes in oil production

capability and trends in surface pressures should also be considered.

Mechanical History A good mechanical review may preclude the successful

application of some workover techniques. Factors to consider include wellbore

restrictions, pipe made weak from corrosion, known poor cement jobs, and perforations

sealed by squeeze cement jobs. The corrosion history, including tubular caliper records,

should be consulted if applicable.

Workover History The results of past well servicing and workover operations

should be studied, including procedures used. Reasons for, and results of, past

workover operations may give indications of the source of the current problem.

19.3.3 Offset Well Performance

The history, workover experience, and performance of offset wells can be compared to that

of the well in question. These data can give insite into the behavior of the well being

considered. However, it is necessary to be sure that the offset wells being compared reflect

conditions and reservoir properties of the well under considerations.

19.3.4 Cross Sections, Maps, Cores And Logs

Cross sections, maps, cores, and open-hole logs all provide information about the producing

zones of a well and the relationship of the well to the rest of the reservoir. For the most part,this information is analyzed by the reservoir engineer who then relays the resulting decisions

to the completion or subsurface engineer.

Geological data, such asstratigr aphic cross sections and structure maps, show the

position of the well in the current reservoir or in a potential recompletion zone.

Open-hole logs and core data can be used, in conjunction with geological data, to


16/30

CM 19



DRILLING DEPARTMENT


define the current gas-oil or water-oil contact, to determine if the well is needed forreservoir depletion in a particular zone, and to evaluate the quality of the pay zone.

Reservoir characteristics such as permeability, porosity, water saturation, relative

permeability, and down-hole pressures can be determined from open-hole logs and core

data. Log and core data also show lithology changes, including continuity of barriers to

vertical permeability and the character of the reservoir rock.

Reservoir mapssuch as isopachous, isobaric, water percentage, and gas-oil ratio mapsare also useful in determining reservoir characteristics to be expected.

19.3.5 Diagnostic Procedures

Diagnostic may be performed to evaluate the well performance.

Well tests such as pressure buildup, pressure falloff, and injectivity tests should be run

where applicable. Review the decline curves for an indication of formation damage.

The current static subsurface pressure and temperature should be determined.

For a dead well that has been shut in for some time, a new production test may be

justified. For example, gas or water fingering or coning may have dissipated, or the

reservoir pressure may have increased.

Production logs should be consulted to check for indications of wellbore

communication and mechanical failures. Additional logging surveys should be run to

detect the source of wellbore communication, as necessary. For pumping wells, check

the fluid level with sonic devices and make dynamometer surveys. For gas lift wells,

consider checking valve operation with flowing subsurface pressure and temperature

surveys.

Special surveys or analyses, which can be run, include wireline gauge surveys to

check for plugging or sanding. Water samples may be analyzed and compared tosamples taken after the initial completion. Bottom-hole sludge samples may be

analyzed for scale, paraffin, or asphaltenes. Scale can also be analyzed from pumps,

tubing, and other down-hole equipment.


17/30

CM 19



DRILLING DEPARTMENT


19.4 ALTERNATIVE OPERATIONS AND TECHNIQUES

After assessing the well condition and determining the cause of the problem behavior, the

subsurface engineer must choose the workover operation best suited to return the well toproduction. The choice of workover operation will influence the workover technique,

equipment, and support services necessary to perform the workover. Other factors which

must be considered include personnel, safety, and contingency planning.

19.4.1 Types Of Workover Operation

Types of workover operations performed to remedy or repair well problems include :

Stimulation Hydraulic fracturing, acid fracturing, matrix acidizing, ball-outs, solvent

and surfactant treatments, thermal stimulation.

Well Clean-out or Blockage Removal washing with water, acids, solvents or

other chemicals.

Sand Control Gravel packing, chemical sand consolidation, resin coated sands.

Perforating

Remedial Cementing Setting plugs, squeeze cementing perforations or channels,

casing repair.

Equipment Replacement and Repair

Production Logging While not a workover itself, production logging is often

included as part of a workover procedure to provide additional well data.

These operations are discussed in more detail in other sections of the next. The operations

most commonly used to treat the well problems previously discussed in this Chapter (Subject


18/30

CM 19



DRILLING DEPARTMENT


19.2) are summarized in Table 1.

Implementation of various workover operations involves many techniques and procedures.

However, all workover techniques can be classified into four major categories.

Bullhead Technique

Wireline Workover Techniques

Concentric Workover Techniques

Conventional Workover Techniques

Each of these techniques is briefly discussed below. More detailed information on these

techniques is included in Chapter 22, Wireline Operations, and Chapter 23, Rig Workover

Operations.

Table 1

Workover Operations Used to Remedy Well Problems

PROBLEM WORKOVER OPERATION

Low Reservoir Pressure Installation of Artificial Lift

Perforation of Additional Interval

Stimulation

Low Reservoir Permeability Hydraulic or Acid Fracturing

Formation Damage Acidizing

Fracturing

Solvent or Surfactant Treatment

Wellbore Restriction Washing Operations

Chemical TreatmentSand Control

High Viscosity Oil Thermal Stimulation

Improper Equipment Sizing/Operation Replace/Modify Equipment

Excessive Water/Gas Production Remedial Cementing/Reperforate

Decrease Production Rate


19/30

CM 19



DRILLING DEPARTMENT


Mechanical Failure Replace Equipment

Remedial Cementing

Primary Cement Failure Remedial Cementing

Recompletion/Perforating

Non-Problem Wells Recompletion/Perforating

Production Logging

Equipment Installation

19.4.2 Bullhead Technique

The bullhead technique is also referred to as a pump-down or pump equipment technique.

The pump lines are usually connected directly to the Christmas tree at the crown valve. The

treatment fluid is pumped through the tree, down the tubing, and into the formation.

Advantages of using this technique are low cost (compared to other techniques) and the

ability to perform the workover without removing the tree or tubulars from the well.

Limitations of this technique are the potential for formation damage, lack of control over

placement of the fluid down-hole, and necessity for good casing and tubing integrity.

19.4.3 Wireline Workover Techniques

Workover operations may also be performed using a wireline. The wireline is run from a

reel on the wireline unit into the well through a lubricator on the christmas tree. Three types

of wireline are available.

Slick Line The wireline is solid, single strand of wire diameter up to 0.092 in.

Braided Line The wireline is a stranded wire, stronger than the slick line.

Commonly used diameters are 3/16in. and 9/16in.

Conductor (Electric) Line The wireline is a stranded wire capable of transmitting a

signal to the surface.

Advantages of using wireline units are low cost, ability to perform the workover without

removing tree and tubulars, and, since the lubricator allows the operations to be performed

under pressure, the ability to perform the workover without killing the well. Limitations of

using wireline techniques include limitations on the size of tools which can be run and risk of

breaking the wirelline.

Wireline techniques are used for operations such as well completion, well clean-out, down-


20/30

CM 19



DRILLING DEPARTMENT


hole equipment installation and retrieval, mechanical repairs, logging, fishing, swabbing, anddepth measurement.

19.4.4 Concentric Workover Techniques

A concentric workover is one in which small diameter tubing used as a workostring is run

inside production tubing to perform down-hole operations. Concentric workover techniques

are performed by three types of units.

Concentric Rig Concentric rigs use small diameter tubing for the workostring.

These rigs are smaller than convrntional workover rigs and thus can be operated at

lower cost.

Coiled-Tubing Unit Coiled-tubing units use a reel of thin-walled tubing for the

workstring. This tubing is fed into the well through an injector head mounted on the

tree.

Snubbing Unit Snubbing units are self-contained, portable systems that are mounted

on the christmas tree and used to push or pull tubing through the rig well control

equipment.

For many operations, concentric workovers techniques are more efficient than the bullheador wireline techniques and more cost effective than conventional workover techniques. In

addition, both coiled-tubing and snubbing units will perform workover operations under

pressure, so it is not necessary to kill the well. Concentric workovers are limited with

respect to the diameter of down-hole tools which can be run. In addition, since higher

pressures are required to pump through the small tubing diameter, higher surface pressures

are encountered than when performing conventional workover operations.

There are few workover or servicing needs that cannot be accomplished using concentric

techniques. Typical workovers include well clean out, remedial cementing, recompletion,

sand control, fishing, and stimulation.

19.4.5 Conventional Workover Techniques

Conventional workover techniques are performed with a heavy-duty rig. In some cases, a

drilling rig may be used. For conventional workovers, the christmas tree is removed, and the

production tubing and down-hole equipment are removed from the well.

The main advantage of using a conventional workover rather than one of the other


21/30

CM 19



DRILLING DEPARTMENT


techniques is flexibility. The main disadvantage is cost.

Conventional workovers can be used to perform any of the operations performed by the

other techniques described above. However, some operations can only be performed by a

conventional rig. These include tubing repair or replacement, down-hole tool repair or

replacement (unless the tool can be run or retrieved on wireline), production casing repair

above a packer, recompletion to a higher zone above a packer, and side track drilling.

19.4.6 Auxiliary Equipment

A detailed cost survey will usually reveal that auxiliary rig tools and equipment cost

approximately as much as the rental rate of the basic workover rig. Thus, as much attention

should be given to the choice of auxiliary equipment as is given to the choice of workover

technique and rig rate.

Contractors vary widely with respect to the tools and equipment furnished with the rig. An

inventory of the equipment provided with a rig will make comparisons of hourly rig rates

more meaningful. In addition, use of an inventory will ensure that all necessary equipment is

on-hand and extra equipment is not ordered.

Some of the more commonly used auxiliary equipment include :

Workstrings and Handling Tools These are high-cost items. If in poor condition,

they can be responsible for many failures and delays because of fishing or well

problems.

Blowout Preventers Contractors usually furnish some type of blowout preventer.

However, the equipment provided may not be rate to handle a potential problem on the

well to be reworked. In addition, the age and testing history of these preventers should

be established to ensure that the preventers are adequate to handle any hazardous

situations which might occur during the workover.

Swab Line Some rigs include a swab line, which can reduce the cost of completion

operations, if the rig is intentionally kept in place until the zone is evaluated. However,

using a rig-provided swab line can be a disadvantage if using it means that the rig is

kept in place at workover-rig rates when it could be replaced by a lower-cost swabbing

unit. In addition, keep in mind that swabbing is a specialized operation. The workover

rig supervisor may not have expertise in swabbing operations comparable to that of a


22/30

CM 19



DRILLING DEPARTMENT


regular swabbing unit operator.

Circulation Pumps Use of the rig pumps for workover operations can eliminate the

cost of units rented from service companies. However, in some cases, the rig pumps

may not have sufficient capacity and pressure rating to perform the necessary

operations.

Tankage Workover rigs sometimes include tankage. The amount of tankage needed

depends on the quantity of circulating and treating fluids needed for workover

operations. The quantity of fluid which must be premixed and on-hand for well control

must also be considered.

Air Slips and Tongs Use of air slips, air tongs and speed equipment allows rig

crews to operate for longer periods of time without fatigue. Proper utilization of this

equipment can double the speed of tripping operations and thus save rig time.

Electrical Equipment Good lighting and generator equipment is fundamental if night

operations are to be conducted.

19.4.7 Support Services

Support services on a workover operation may cost as much as, more than, the basic rig

rental. Control over support services is often the key to keeping costs within projected goals.

It is false economy, however, to settle for lower cost services if this means sacrificing the

quality of the services provided.

Support services used for workovers include :

Wellsite preparation and rig transportation

Cementing and well treating

Stimulation

Removal of paraffin, sand etc.

Fishing tools and service

Equipment rental (Accessory equipment, packers, tubing, artificial lift equipment)


23/30

CM 19



DRILLING DEPARTMENT


Wireline operations

19.4.8 Other Considerations

Other factors which should be considered when selecting workover techniques and

equipment include safety, personnel and contingency planning.

Safety In any operation, safety of the personnel is the most important factor. Every

employee has the responsibility to properly use equipment, to maintain it in good

condition, to observe the established working rules at all times, and to practice the

principles taught in safety training.

In addition, company personnel at the rig site should be sure that the rig and service

company personnel are aware of and observe the established safety rules. This can be

facilitated by holding pre-job meetings to inform al lon-site personnel of safety hazards,

safety equipment location and use, and established safety rules.

Personnel Rigs are often chosen on the strength and capability of the equipment. In

practice, personnel and supervision on a particular rig are often of equal importance to

the equipment brought to the rig site. The number of men in the rig crew often dictatesthe efficiency of operations. The quality of contractor supervision is extremely

important on a workover rig.

The relief schedule of a contractor is also important. Contractors who work men for

longer periods of time without providing relief penalize the operator with lower

efficiency during the latter part of the tour of duty.

Associated with this concept are the employment practices of a contractor during slack

periods. Some contractors maintain key supervisors on a full-time basis but pay rig

crews only when work is available. This can result in rig crews with low experience

levels.

Contingency Planning Although extra, non-used equipment on-site may represent

additional cost to the workover operation, enough back-up equipment should be on hand

to plan for contingencies. When planning the workover, consider what could go wrong

with the operations and plan accordingly. Pre-planning and availability of critical back-

up equipment can save time and money in the long run.


24/30

CM 19



DRILLING DEPARTMENT


19.5 EVALUATING AND SELECTING A TECHNIQUE

After assessing the problem and reviewing alternative techniques, the engineer should

evaluate the best alternative techniques with respect to economics, limitations and

capabilities of the technique, and other factors such as safety, expedience, and reliability.

Often, the least expensive workover is not the best workover when factors other than cost

are considered.

19.5.1 Economic Analysis

When evaluating the economics of a single proposal or comparing economics of competitive

proposal, the following questions should be considered :

Cost What is the relative cost of alternative workover techniques, including rig time,

auxiliary equipment rentals, and support services.

Current Income What will be the effect of performing the proposed workover, or

possible alternative workovers, on current income?

Increased Recovery Is the well needed for optimum ultimate recovery in the

present completion interval or in possible new completion intervals? If well stimulation

is contemplated, would successful stimulation increase recovery?

Payout What is the direct payout, i.e., the length of time required for the total cash

outlay to be recovered through the new cash inflow generated by the project?


25/30

CM 19



DRILLING DEPARTMENT


Rate of Return How much additional income is expected to result from the

workover after the payout period? How soon can this be realized?

Loss in Deferring Workover If the workover is postponed, what would the cost

be? Would impending additional recovery programs render workover of this well more

attractive in the future?

Risk What is the risk factor? The degree of risk should be weighed against

anticipated gain from a successful job. The degree of risk should be assessed through

past experiences in areas with similar type of work or in the same or comparable

reservoirs and wells, plus individual judgement based on available data concerning thewell and reservoir.

19.5.2 Capabilities/Limitations

As discussed earlier in this Chapter (Subject 19.4), the choice of workover technique is

sometimes limited by the capabilities and limitations of the workover rig units. For example,

treatment operations, such as remedial cementing, matrix acidizing, and corrosion treatments,

sometimes require that the treatment fluid selectively placed into a single zone or portion of a

zone. While wireline and concentric techniques have some flexibility in this respect, use of aconventional workover rig allows use of the full casing ID and thus a wider range of down-

hole tools and packers can be used.

On offshore locations, the compactness of wireline and concentric units is a premium. In

addition, wireline units are the quickest and most efficient, thus reducing rig time, a major

expense on offshore locations.

Conventional rigs are slow and cumbersome; however, they are not as limited by factors

such as operating depth, high bottom-hole temperatures and pressures, and severe ID

restrictions. All of these factors must be considered before selecting a particular workover

technique to perform the desired workover operation.

19.5.3 Other Considerations

Well or reservoir safety, lease obligations, government regulations, reliability of a particular

workover operation in the area, and the ease with which a particular operation can be

performed may justify a decision to perform a workover even when economics do not.


26/30

CM 19



DRILLING DEPARTMENT


19.6 JOB EXECUTION AND FOLLOW-UP

In addition to selecting the best technique and equipment to perform the workover, a

successful workover operation depends on correct and efficient implementation of the

workover procedure in the field. Successful field operations can be facilitated by a well

written workover procedure and sufficiently supervised field operations. In addition, future

operations can be improved by the experience of past operations if workover results are

analyzed and proper records maintained.

19.6.1 Workover Procedure

A well written workover procedure will communicate all details of the procedures planned

for the workover operation, especially when non-routine procedures are being used. It

should not be assumed that the field personnel will automatically perform a certain step in a

procedure because the procedure has always been done that way. Lack of details can

lead to costly mistakes such as stuck tubing, lost tools, and misplaced treating fluids.

Essential components of a well written workover procedure include :

Well Sketch A sketch of the wellbore before and after the workover.

Procedure Steps A step-by-step description of the workover procedure, pointing out

steps at which problems may arise.


27/30

CM 19



DRILLING DEPARTMENT


Alternative Procedures Alternatives for procedures where problems areanticipated.

Calculated Values Values of parameters such as treatment depths, displacement

volumes, treatment volumes, maximum treating pressures and rate are essential to the

proper implementation of the workover. Including values for parameters such as casing

and tubing capacities, fracture and fluid gradients, and other parameters used in the pre-

job calculations can be helpful if last minute checks or changes are needed in the field.

Safety Hazards/Rules Any safety hazards, rules, or regulations should be clearly

described and emphasized.

Contingency Plans Contingency plans in case of unexpected events such as

encountering H2S, lost circulation, or well control problems should be included as

attachments to the procedure.

Contracts A list of person to contact, with phone numbers, in case of problems or

emergencies should also be attached.

19.6.2 Field Operations

Field operations should be supervised by competent personnel. For routine workovers,

adequate supervision can often by provided by the rig supervisor. However, for non-routine,

hazardous or critical well operations, a company representative should be on hand.

The importance of good communication between engineering and field personnel cannot be

overemphasized. Even the best planned workover procedure will not be successful if the

importance of critical steps and procedures are not communicated to, and understood by, the

field personnel.

Safety rules, precautions, and emergency procedures should be explained to all personnel on-

site during the workover operation. This is best achieved by pre-job meetings of all persons

involved. It should not be assumed that personnel will follow safety precautions just because

they have been informed. It is necessary to observe operations and enforce rules.

19.6.3 Analysis of Results

The success or failure of operations used on a workover are often valuable information to

help plan future workovers. The procedures used in the field should be noted and compared

with the planned procedure. Results should be recorded along with unexpected problems or

behavior. If the workover fails, or is unexpectedly successful, the procedures used should be

analyzed to determine the cause, if possible.


28/30

CM 19



DRILLING DEPARTMENT


If the results are to be useful for future workovers, as many details as possible regarding the

actual procedures used should be recorded.

19.6.4 Record Keeping

The workover results, field procedures (both planned and actual), logs, and service lab

records are all valuable components of the history of the well. These records should be

placed in the well file and stored in the company office. As mentioned above, these records

are a valuable source of information for planning future workover operations.

When available, records should be entered into a computer database to facilitate comparison

of results from a large number of wells. However, the information which can be obtained

from a computer database is only as useful as the data entered. When establishing a

database management system, keep in mind the types of data which will be used for future

workover planning.

19.7 WELL ANALYSIS CHECKLIST

19.7.1 Well Completion Characteristics

1. a. Completion type

b. Pressure ratings of casing and tubulars and wellhead equipment

c. Producing zone characteristics permeability, porosity, consolidation

d. Producing zone fluid properties density, salinity

e. Reservoir considerations reservoir pressure, drive mechanism, structure

position, current and allowable productivity, ultimate recovery desired,

forecasted behavior, recovery from offset wells.

19.7.2 Well History

2. a. Drilling procedures fluids, problems, lost circulation


29/30

CM 19



DRILLING DEPARTMENT


b. Initial completion when, how, cement job data, problems during completion,initial fluids, perforation pattern

c. Production history pressure, fluids, rates, gas-oil ratio, water-oil ratio, dates of

initial gas or water production, trends

d. Mechanical history corroded pipe, poor cement jobs, squeezed perforations

e. Workover history

19.7.3 Offset Well Performance

3. a. Relative structural position

b. Comparison of behavior

19.7.4 Cross Sections, Maps, Cores and Logs

4. a. Stratigraphic cross sections

b. Structure, isopachous, isobaric, water percentage and gas-oil ration maps

c. Open-hole logs

d. Core data

19.7.5 Diagnostic Procedures

5. a. Well tests pressure buildup, pressure decline, injectivity, production test

b. Production logs noise, temperature, sonic, flow-meters, pressure bombs,

tubing calipers

c. Water analyses


30/30

CM 19



d. Wireline depth or gauge surveys

e. Bottom-hole sludge samples

f. Scale samples

19.8 REFERENCES

1. T.O. Allen and A. P. Roberts,Production Operations, Vol.2, Chapters 1 and 12,

Oil & Gas Consultants International, Inc., Tulsa, 1978.

workover planning

Documents