Well Integrity for Workovers and Recompletions

By Les Skinner

Well Integrity for Workovers and Recompletions delivers the concise steps and processes necessary to ensure that production wells minimize failure. After understanding the introductory background on well integrity and establishing the best baseline, the reference advances into various failure modes that can be expected. Rounding out with an explanation and tools concerning economic considerations, such as how to increase reserve potential and rate of return, the book gives oil and gas engineers and managers a vital solution to keeping their assets safe and effective for the long-term gain.

• Helps readers understand how to protect wells through the production, workover and recompletion lifecycle, both from an economic standpoint and technical view
• Includes real-world examples with quizzes included at the end of each chapter
• Examines why establishing an integrity baseline is important, along with a Well Integrity Management System

• Language: English
• Publisher: Elsevier Science
• Release date: Feb 25, 2021
• ISBN: 9780128182093

Les Skinner

Les Skinner graduated in 1972 with a BS in Chemical Engineering from Texas Tech University. He is a PE who has worked in the petroleum industry for 50 years. Les has written numerous articles for industry publications and authored three full-length books through the International Association of Drilling Contractors (IADC)’s Technical Publications Committee. These include Coiled Tubing Operations (IADC, 2016), Hydraulic Rig Technology and Operations (Elsevier, 2019), Well Integrity for Workovers and Recompletions (Elsevier, 2021) and Well Integrity for Abandoned Well Re-entries (2024). Les is a member of several professional societies and associations including SPE, ICoTA, AIChE, AADE, IADC and others. He is also a member of multiple industry committees including the API Recommended Practice 1170/1171, RP 90-1 revision committee (which he chaired for five years), and the ISO 16530 revision team. He is currently on the Steering Committee for AADE’s Innovative and Emerging Technology group and ICoTA’s Technical Committee

Book preview

CHAPTER 1

Introduction and definitions

Chapter Outline

1.1. Scope of this book 2

1.2. Nomenclature, workovers, and recompletions 3

1.2.1 Workover 3

1.2.2 Recompletion 4

1.3. Other definitions 6

1.3.1 Operator 6

1.3.2 Working interest owner 7

1.3.3 Royalty owner 7

1.3.4 Overriding royalty interest 8

1.3.5 Net revenue interest 9

1.3.6 Overhead 9

1.4. This book's organization 9

Chapter Quiz 10

Bibliography 13

Abstract

This chapter introduces the importance of good well integrity following initial completion. Initial well integrity begins during the basis of design for a new well, and its actual design. It is assured during well construction. New well integrity is the subject of many books and papers. Far less discussed is well integrity for the existing well, especially one that has been in-service for some time following initial completion. There is no common definition for the terms workover and recompletion in the industry. For this book, a workover is significant well work performed to improve or restore production/injection from an existing completion interval. A recompletion is work involved in opening a new source of supply. Several terms involving well integrity are defined for use later in the book.

Keywords

Integrity; stability; workover; recompletion; operator; interest; royalty; revenue; owner

Well integrity has always been a primary objective in the basis of design, well design, and construction. Maintaining that integrity through initial completion, production operations, workovers, recompletions, and abandonment has been a potential problem since the first wells were drilled over 4000 years ago using spring poles.

Literature is filled with accounts of wellbores collapsing due to poor borehole stability especially near the surface where rock strength is poor. This led to the installation of rigid conductors to reinforce the shallow borehole and prevent near-surface sloughing centuries ago. Some of the earliest conductors were simply hollowed-out tree trunks that kept the well from cratering at the surface as it was being drilled. This simple item avoided much frustration, cost, and the disgust of the investors financing the operation who justifiably asked, Why did you not think of this earlier?

Now, the issue of well integrity has gone past those early days as both the depth and the forces applied to wells have increased to reach deeper, hotter, higher-pressured formations. Borehole stability, the portion of well integrity that deals with the newly drilled open hole, involves all sorts of complex problems with rock strength, formation stability, and geomechanics.

Once the well is equipped with casing, borehole stability is no longer an issue, and the focus shifts to efforts involving maintenance of the well's mechanical condition over a given time frame. The well must withstand all the rigors and forces imposed on it during the initial completion, subsequent production, or injection, all types of work on the hole, and mechanical reconfiguration changes while providing the reliability to ensure that reservoir fluids will not leak into the surface environment or into another formation below the surface, including fresh water sources. The goal is to keep reservoir fluids inside the reservoir until they are safely transported to the surface through a secure conduit and sold.

At some point, every well must be abandoned. Long-term well integrity has taken on a new meaning lately. It is not enough to keep an old, plugged well from leaking for the next few years. Now, the industry is talking about a thousand-year plug and well integrity that will last, essentially, forever if that is possible. Old leaking wells are just as bad as new leaking wells.

1.1 Scope of this book

This book deals with well integrity during the middle portion of the life of a well, after initial completion and before abandonment. This typically covers a significant portion of the well's service life. That service length could be rather short, a few months in some cases, or it could be decades. There are wells still producing that were initially completed over 100 years ago!

Production operations and those efforts intended to simply maintain the well are not the focus of this book. Maintenance is certainly impacted by well integrity, but most of this type work does not significantly impact well integrity. The stresses imposed on the wellbore by workovers and recompletion operations can have immediate and far-reaching impacts.

This book concentrates on well integrity during work performed on the well subsequent to its initial completion. Jobs performed during this time span include normal production maintenance and involve such things as corrosion and scale inhibitor squeezes, pump change-outs, paraffin cleanups and surface or subsurface valve replacements.

Workover and recompletion procedures place greater stress on the well than those experienced during routine production. These stresses can involve imposed pressures, thermal contraction or expansion, added torque, and other work-related damage to tubular goods and well head components. Just running the workstring in the well and recovering it, often multiple times during a workover or completion procedure, can abrade critical well construction elements previously worn by similar pipe tripping. If fishing or drilling tools are involved, point-wear during pipe rotation can easily damage casing. Setting and releasing certain tools such as packers, whipstocks, and retainers can also compromise casing, especially in older wells.

Equally important are the stresses imposed on a wellbore following the procedure. Added pressure, temperatures, corrosion, and erosion resulting from the production of fluids following a workover or recompletion can push an older well beyond its capacity to perform without leakage. A well must provide a reliable well subsequent to the job for some time period to guarantee the economic longevity of recovery. It does not make sense to spend the money on an expensive workover or recompletion and end up with a well that only produces for a few days after the job before it fails in some manner as a result of newly imposed stresses that resulted from the workover or recompletion work.

This is a rather broad topic when one considers the plethora of possible workover and recompletion procedures to improve production or injectivity, all of which are driven by economic considerations. If the job is not economically feasible, there is no reason to perform it; the well has reached the end of its life. Abandonment may be the only remaining option.

1.2 Nomenclature, workovers, and recompletions

One of the greatest issues in communication of all types is the lack of understanding that comes from differences in terminology. One person's concept of a term differs from another person's, so there is an immediate disconnect just in terminology. The field of well integrity has many terms in use today, some of which are well-defined, others are anybody's guess on any given day. Will Rogers, a well-known American humorist, made the point once that It isn't what we don't know that gives us trouble, it's what we know that just ain't so.

Appendix A includes a list of Acronyms and Abbreviations used throughout this book. Appendix B is a Glossary of Terms that provides a definition of many of these terms. Both of these are intended to clarify some of the issues with terminology. There is still some dispute over the terms workover and recompletion, however.

Exactly what is a workover? What is a recompletion? There are lots of definitions of these two terms and they vary depending on viewpoint, political and regulatory drivers, public perception, job difficulty or extent, and sometimes cost. There is no consensus on the definitions of these two terms across the industry (Appendix C).

Some additional terms are used to define work on a well subsequent to its initial completion. One of these is well intervention, a catchy term that should be all encompassing including normal maintenance and other work on an existing well. Recently, it has been used to describe abandonment and site cleanup. Another term is well servicing which could include some work to sustain production through stimulations, artificial lift installation, or cleanouts. Another term is re-entry that is used to describe anything done to the well after the initial completion since the well was no longer in its original configuration during the work. Another term is remediation or remedial work again to describe something done to the well after its original completion. The term remediation is largely used by the environmental community to denote cleanup operations after a spill. Again, there is no agreement as to what these various terms mean everywhere.

The specific terms workover and recompletion in use today are often confusing. Sometimes, they are used interchangeably to denote any job performed on the well after initial drilling, equipping, and completion. Sometimes, they are used to include abandonment activities as well. They often include normal production/injection maintenance work. One definition of a workover involves the difficulty and cost of a job to decide when it is a normal maintenance activity or a major workover. Presumably, minor workovers are not really workovers at all.

For the purposes of this book, only certain jobs are considered workovers and others are recompletions.

1.2.1 Workover

The term workover is used in this book to denote significant downhole work in a wellbore for the purpose of improving production or injection rate in the current completion interval only. Some examples of workovers include:

• Acid or fracture stimulations;

• Scale or paraffin removal jobs that require pulling the tubing string and artificial lift equipment;

• Installation of artificial lift equipment of all types on a previously flowing well;

• Significant casing repairs such as cement squeezes to eliminate water production from an uphole leak;

• Re-perforating an existing zone, including adding more perforations;

• Squeezing off or otherwise isolating a portion of the perforated interval in an existing completion.

Workovers, unlike maintenance activities, usually require breaking a flow or pressure barrier. The formation must be accessed somehow. Some workovers can be performed without significantly disturbing the existing mechanical configuration of a well, such as a through-tubing stimulation or re-perforation using wireline only. Other procedures are sufficiently strenuous to threaten the integrity of the tubing or casing installed in a well.

Normal, routine production/injection maintenance jobs are usually not considered workovers. These might include such well work as:

• Changing out artificial lift equipment such as a worn downhole pump, parted sucker rods, leaking gas lift valves or a burned-out electrical submersible pump (ESP) even though this work could require pulling the tubing string;

• Jetting sand fill from the perforations using coiled tubing and nitrogen;

• Squeezing a relatively small volume of fluid into the perforations containing scale, corrosion, or paraffin inhibitor;

• Running wireline production/injection logs over an existing perforated interval; and,

• Performing various types of tests that do not change the well's configuration or function such as pressure build-up/fall-off tests, step-rate tests on injectors, or temperature/noise logs.

Some otherwise routine production/maintenance jobs could be considered workovers by an Operator depending on extent, complexity, or cost. Consider, for example, a scale removal job that first involved spotting chemicals across the perforations using coiled tubing. The job may not have the desired results, so the tubing string is pulled to permit milling the scale from the perforated interval, and then returning the tubing to its original position in the wellbore. An acid wash through coiled tubing could then be required to restore production. The combination of these efforts might take the work from routine maintenance into the workover category simply due to the complexity and cost of the job.

Similarly, routine wireline monitoring of an injection well could progress into a workover if the wireline parts requiring fishing and pulling the tubing and injection packer.

It is noted that multiple workovers can be performed on a producer or injector over its lifetime. This applies to the time period following the initial completion and before any recompletions performed on the well. After the well is recompleted, a number of workovers can then be performed until the next recompletion or abandonment.

1.2.2 Recompletion

For the purposes of this book, the term recompletion applies to downhole work on a well that accesses a new source of supply (for producers) or a new injection interval. It can also involve a significant alteration of the well's mechanical configuration to convert it from one type of service to another. A workover involves operations on an existing zone; a recompletion involves operations to open a new reservoir or to change the configuration of a well and convert it to new service.

There are eight general types of recompletions;

• Plug (or somehow isolate) the existing perforations and perforate a shallower zone in the well;

• Add perforations in new reservoirs to the existing producing zone perforations and commingle production from all the reservoirs;

• Plug the existing perforations and perforate in a deeper interval;

• Reconfigure the well and change its type of service, say, from production to injection;

• Plug the existing perforations and deepen the well below the casing shoe;

• Sidetrack the well in the existing producing interval and drill a lateral hole section to access more reservoir area;

• Plug the existing perforations, sidetrack the well, and drill a lateral hole section in a new reservoir;

• Isolate the existing perforations, plug back to some point up the hole, and sidetrack the well to another location in the field.

The first four of these general recompletion types involve only work inside the existing wellbore. The last four require drilling a new hole segment outside the wellbore. Drilling a new hole segment involves all of the borehole stability issues of drilling any new hole. Drilling a new hole segment from an existing wellbore introduces stability issues from the point in the well at which the new hole section begins.

Well integrity issues in the newly equipped hole section are the same as those for any new well. What is different is that these well integrity issues are now coupled with the integrity in the old, existing wellbore. The newly equipped hole section may be completely capable of withstanding forces involved with producing from or injecting into the new reservoir. The older wellbore segments up the hole may not be.

Several of these recompletion procedures are straightforward and easy to understand, such as those involving plugging off existing perforations and adding perforations in new intervals. Adding a lateral hole in the existing zone may seem more like a workover since it involves the same reservoir before and after the job; however, more reserves from the interval can now be produced thanks to the lateral. The job therefore qualifies as a recompletion under the definition of adding a new source of supply.

In the same way, if a well is plugged back and sidetracked to a new position in the field even if it is completed in the same reservoir, more reserves are available to be produced at the new bottomhole location. So, the job is considered a recompletion instead of an expensive workover.

One job type that can be a bit confusing is a sidetrack outside of an existing wellbore to restore production from the original reservoir near the well's original bottomhole location. This is sometimes required to re-access an existing reserve accumulation when an obstruction above the perforations does not permit its production. Examples of these obstructions include unrecoverable junk, collapsed tubing, split casing, or blockage due to compromised sand-exclusion equipment such as a collapsed or short-circuited screen. In these situations, the goal is to get a producing well back to the original zone at about the same well position as the original hole.

For this book, the so-called blind sidetrack job would be considered a very expensive workover since the goal is to produce reserves from the original completion zone at, essentially, the original well position in the same reservoir. If the well is sidetracked a significant distance away from the original wellbore with the goal to access a new reserve accumulation, the job would be considered a recompletion.

Whether a job is defined as a workover or a recompletion may be determined by regulation. In some jurisdictions, all work in an existing producing/injection reservoir is considered a workover regardless of job type (as discussed in Appendix C). This includes maintenance operations. It also includes sidetracks to add a new lateral hole segment in the same reservoir, since a new reservoir is not involved.

In general, workovers can be performed without requesting permission from the regulatory agency. That agency's objectives are to protect correlative rights between offset Operator(s) and to prevent waste. Correlative rights are those that protect one landowner or reservoir owner against drainage by some other owner. Improving performance through a workover usually does not threaten either correlative rights or result in waste.

If a new reservoir is to be opened, permission from the regulatory agency is usually required. Anytime a new reservoir is exposed, regulatory agencies tend to exercise their authority to manage it, whether the job involves drilling a new well or recompleting an old one. Workovers to improve production from an existing reservoir and extend well life usually do not require such permission. Changes in well function, say from production to injection, may or may not require permission from the regulatory authority.

1.3 Other definitions

Several other terms deserve to be clearly defined before entering into a discussion on well integrity and its impact on workovers and recompletions. These mostly apply to economics. Justification for work performed on existing wells is predicated on economic viability of the investment in doing the job. Very few investments in today's economic world are made for the sake of science.

1.3.1 Operator

The well's Operator, or the oil company, is the person charged with the day-to-day operation of the well. The Operator has the obligation to produce the well at the optimum rate to maximize economic return or to inject fluid to facilitate production from an offset well. This may include disposing of produced fluid in other service wells or to remove it from the property for disposal offsite.

The Operator is also the party to which regulatory authorities look to prevent discharges to the environment, maintain permits of various types, carry sufficient economic viability for future abandonment, and prevent waste (loss of resources, primarily oil and gas reserves). The Operator is expected to perform its duties ethically and in compliance with existing laws, rules, and regulations. Failure to do so could result in sanctions such as fines, the loss of its license to operate, and, in a worst-case scenario, civil and criminal prosecution both of the corporation and of individuals within the business.

In this book, the term Operator (with a capital O) is the oil company or individual charged with fulfilling these duties. Another term starting with a lower-case o, operator, is used to describe the person who runs a piece of equipment (e.g., the operator of a snubbing unit). Another example of an operator would be a pneumatic device that controls a gate valve on a production tree (a valve stack) at the surface.

1.3.2 Working interest owner

A working interest owner (WIO) is an entity that owns a portion of the well, and which shares costs and revenue from a well's production after taxes, royalty, and operating expense. A WIO is often the person or corporation that invests the capital required to drill and complete the well, and who is required under an operating agreement to pay his share of future maintenance costs and additional investments required to increase or maintain production/injection through workovers and recompletions.

In short, this is the entity that shares both in the cost of the well and in revenue from it on the basis of its ownership fraction. Often, the Operator is the largest WIO in a well. Other WIOs are referred to as non-operating WIOs. Sometimes, the Operator is the only WIO having 100% ownership in the well and lease.

Another important concept is that working interest ownership sometimes differs from zone to zone within a single wellbore. This has to do with the leasehold positions of various WIOs segregated by depth or producing horizon. So, there may be one set of WIOs when the well is producing from or injecting into one zone and a completely different set of WIOs (or the same WIOs with different proportional ownership) in another zone even though it is the same wellbore. This can get quite confusing and contentious when there are disputes on the precise level of ownership in a particular reservoir penetrated by the wellbore.

WIOs are often able to deduct a certain portion of their investment in well work from their taxes. In the United States, a WIO is able to deduct all intangible costs (work, fluids, supervision, etc.) at the time they are expended. The costs of some tangible goods (casing, tubing, well heads, etc.) are handled through a different system involving depreciation. In some areas, WIOs are allowed to recover all of their out-of-pocket costs before the mineral owner begins collecting any revenue. The taxing structure that applies to a given investment can improve the overall economic attractiveness of a workover or recompletion, or it can make the job infeasible.

Certain lease operating agreements allow a WIO to decline participation in a capital investment without losing his interest completely. Some agreements contain penalty provisions that allow the WIO to back in after some level of revenue has been returned to the participating WIOs. For example, if a group of WIOs decide to recomplete a well to a new zone and one WIO declines to participate, that WIO receives no revenue from his share of the well until the participating WIOs recover three times their investment from production. At that time, and with no further penalty, the declining WIO backs in for his proportional ownership and pays his share of costs from that point forward. Again, this can all be quite confusing and occasionally contentious.

1.3.3 Royalty owner

This is a mineral owner who has leased, or licensed, his property to a WIO to explore for oil and gas, another mineral such as coal, precious metals or potash, or even water. The royalty owner (RO) usually makes no investment in the well and is not subject to paying any other capital cost. In some situations, the RO is also a WIO.

The RO generally receives compensation from the sale of hydrocarbons before any expenses or taxes are deducted. There are some exempted uses of part of the hydrocarbons in many lease agreements. For example, if the Operator uses part of the gas produced by the well for fuel on the lease, that gas volume is consumed before the sale of any excess gas through a pipeline. The fuel gas is usually not subject to royalty payment. Unauthorized losses, such as spills and emissions, are not exempt from royalty payments, however.

Again, royalty ownership can be segregated by depth depending on mineral ownership leased to the Operator or a group of WIOs. This can lead to issues when royalty payments from a particular reservoir cease after a well is recompleted to another zone up the hole. RO demands on the WIOs for increased production, and therefore higher royal payments, can become problematic when executing a strategy for the economic depletion of a well or field. Sometimes these demands result in litigation or other forms of pressure on the Operator.

In general, royalties on new leases have increased with time. In the early days of the oil industry, mineral owners were simply paid a fee to explore for minerals at the beginning of lease. There were no further royalty payments based on production. Then, Operators began paying a lower initial fee for drilling and producing minerals, but they added a small payment based on how much the well produced. This placed a portion of the risk of drilling a producing well back onto the mineral owners. If the Operator drilled a dry hole (a well not capable of producing in commercial quantities), he had only spent a small amount of money for the privilege of exploring the lease, and the RO got nothing from future production.

Early on, royalty payments amounted to less than 5% of the revenue from sales. For several years, the common royalty was 12½% (one-eighth). Later, royalty rates increased to 16.7%, then to 20%, and then higher. Now, some highly desirable, competitive leases carry much higher royalties; sometimes over 40% of the revenue from mineral sales.

In those countries where the state owns the minerals, there is only one RO. The amount of revenue sharing is often negotiated and established by the exploration/production contract, or license, for a particular area. Again, there may be situations in which royalty payments may be delayed until some threshold recovery value has been achieved by the Operator.

1.3.4 Overriding royalty interest

An overriding royalty interest (ORRI) is a special interest awarded to an individual or corporate entity that is in addition to the royalty paid to the mineral owner. This is often used as an incentive bonus awarded to professionals within the Operator's organization such as geologists, geophysicists, or engineers. Once awarded, these royalties become the personal property of the individual and survive for the life of the lease even if the property is divested (sold) to another Operator. These are usually small interests, but like the RO they are exempt from capital investments or operating costs. They are named because they are royalties that are paid above that royalty owed to the mineral owner, so they override the lease mineral interest royalty.

ORRIs only have value as long as the well is generating revenue from the sale of oil and gas. Like other royalties, ORRIs can also be depth segregated, so when production from one interval ceases, some or all of the ORRIs associated with that interval also cease. If the well is recompleted, a new set of ROs and ORRIs may then exist for the new interval depending on the agreement. Often, both the ROs and ORRIs are the same throughout the entire wellbore and lease.

1.3.5 Net revenue interest

A net revenue interest (NRI) is the fraction of revenue the WIO can expect from his working ownership in a well or lease after royalty. The royalty here is all royalties including RI and ORRIs.

This is best illustrated by example. Assume a lease has a 20% royalty payable to the original mineral owners. There is also a 3% ORRI. Assume that the Operator has a 60% WI.

(1.1)

where NRI is the net revenue interest, fraction; WI is the working interest, fraction; RI is the royalty interest, fraction, and; ORRI is the overriding royalty interest, fraction.

For this example:

The 60% WIO would have an NRI of 46.2% so he would be required to pay 60% of all investments, lease operating costs, and taxes. He would receive 46.2% of revenue from future product sales. A similar calculation would apply to all the other WIOs for this lease based only on their individual working interest ownership; both the RI and ORRI would remain the same.

The WI and NRI become factors during economic calculations to determine the practicability of performing a workover or recompletion. Sometimes, the RI and ORRI burden on production is too great for the well to make an adequate return.

1.3.6 Overhead

Overhead is a set fee the Operator charges the other WIOs to compensate it for performing administrative duties involved in operating the lease. The amount of the overhead fee is usually established by the lease operating agreement. Each non-operating WIO must pay his portion of this fee on a working interest basis. The Operator does not pay itself overhead. The overhead fee is in addition to each WIOs proportional share of taxes and operating cost.

When a well is approaching the end of its economic life as a producer, the Operator still has a small source of income from the overhead it charges the other WIOs. This means that a low productivity well/lease may be uneconomical for non-operating WIOs (i.e., production revenue is less than cost), but it is still barely economical for the Operator. In these situations, the non-operating WIOs often request that the Operator do something to make the operation economical for them although the Operator may not be inclined to do so.

1.4 This book's organization

This book is intentionally organized by topic with each chapter generally covering a single aspect of workovers and recompletions. These include such items as failure modes relating to well integrity problems, diagnostic tools to identify problems, economics, and procedures for workovers and recompletions. In each case, the chapter provides examples in the form of case studies, discussion, and illustrations on subject matter.

At the end of each chapter is a short quiz. Some of the questions are multiple choice, some are true or false. All are intended to reveal the reader's comprehension of the subject material covered in a chapter. Answers to each quiz question are included in Appendix F at the end of the book.

The questions are not intended to confuse the reader, nor are there a bunch of gotcha questions. The answer key contains explanations to hopefully avoid confusion when the correct answer is not obvious.

Each chapter also includes a bibliography of resources that can be used to explore the chapter topic in greater depth at the reader's option. The list of texts and papers included in the bibliography is not exhaustive—it does not include every publication on the topic nor does it attempt to steer the reader toward one source or away from another. It is simply a list of other resources available for additional study.

All books on specific portions of an industry include some nomenclature and term usage that can add confusion. The text includes explanations of most terms, and there is a Glossary (Appendix B) for reference.

It is recommended that the reader go through the text sequentially since most of the topics build on the one covered in a previous chapter. For example, the diagnostics chapter is best read following the failure modes chapter so the reader can appreciate how certain diagnostic tools operate, what information they provide, and why they are used. If the reader understands well integrity failure modes already, the diagnostics chapter will make more sense.

This book, like all other similar books, is merely a snapshot in time. Technology constantly improves as the oilfield matures. Something discussed here may be obsolete even before the book can be printed. Each reader is encouraged to come to conclusions and make recommendations based on his/her own judgment, analysis of the individual well, and currently available technology.

There is no such thing as a good cookbook recipe for dealing with all well integrity situations because no two wells are exactly alike in every respect. Assumptions rarely provide the proper basis for dealing with any aspect of oil and gas wells. Good data, good judgment, and good operations are the best bet for a successful outcome. Recall that Mother Nature usually sides with the hidden flaw.

Chapter Quiz

1.Well integrity must be maintained during each phase of a well's life from the basis of design through abandonment.

a.True______

b.False_____

2.Why can a workover or recompletion result in a leak in an otherwise trouble-free existing producing well?

a.Workover and recompletion procedures place greater stress on the wellbore than it usually experiences during normal production operations

b.Greater production from the same or another reservoir following the procedure can place additional stress on the well

c.A recompletion can expose the well to higher pressure from a newly completed reservoir than that experienced by the producing well from the existing interval

d.All of the above

3.The term workover for the purposes of this book involves a procedure intended to improve performance or to extend well life from an existing completion interval.

a.True______

b.False_____

4.Which of the following is a workover procedure?

a.Well head valve repair

b.Acid stimulation

c.Pulling and changing out a downhole pump

d.Running cased hole wireline logs over an existing perforated interval

5.A recompletion differs from a workover in what way?

a.Which barrier elements must be opened

b.The difference in total job cost

c.The type of rig involved in the procedure

d.The source of supply of oil and gas

6.A recompletion only involves plugging or isolating the current completion interval and perforating a new zone through the production casing.

a.True______

b.False_____

7.How many general recompletion categories are discussed in this book?

a.Four

b.Six

c.Eight

d.Hundreds

8.A job to reconfigure the well to new service, say from a producer to an injector, is considered what type of job?

a.A recompletion since new reserves will likely be produced as a result of the reconfiguration

b.A workover since it does not include perforating a new interval

c.A stimulation since the new service requires acid to clean up the perforations

d.A new well since permission from a regulatory agency is required

9.When a new hole section must be drilled from an existing wellbore as part of a recompletion, the old wellbore above the casing exit depth is subjected to the same hydraulic and mechanical stresses as a newly drilled well.

a.True _____

b.False_____

10.What is involved in a blind sidetrack?

a.Plugging back, exiting the casing, and drilling a new hole section while steering the well a considerable distance away from the current completion site to a new bottomhole location somewhere in the reservoir

b.Milling out junk inside the wellbore above the existing perforations to restore production

c.Exiting the production casing and drilling a horizontal lateral in a new reservoir at some depth up the hole from the existing perforated interval

d.Plugging back, exiting the casing, and drilling around junk above the current perforations, penetrating the same reservoir at roughly the same position in the field, and completing the well in the same reservoir from which it was producing prior to the sidetrack operation

11.A blind sidetrack is considered a recompletion.

a.True______

b.False_____

12.What is a working interest owner?

a.A business organization or individual that is required to pay its/his proportional share of the cost of operating the well

b.An individual or business that operates the well (i.e., the Operator)

c.A business or individual that receives an overriding royalty interest from the sale of hydrocarbons from a lease

d.All of the above

13.Royalty owners and overriding royalty owners are able to deduct a portion of the cost of operating the lease either through tax benefits or as normal business expenses.

a.True _____

b.False_____

14.What is a net revenue interest?

a.The fraction of the cost of drilling, completing, and equipping the well that a working interest owner must pay at the beginning of the well

b.The portion of money from the sale of hydrocarbons that accrues to a working interest owner after royalties

c.The proportional share of taxes, royalty, and operating cost that the working interest owner must pay on a monthly basis

d.None of the above

15.What is the purpose of overhead that the Operator charges to the other working interest owners in a lease?

a.It provides the Operator with a continuing monetary reward from the other working interest owners for drilling the well and placing it on production

b.It allows the royalty owners the opportunity to participate in the operation of the lease

c.It is a continuous source of revenue for the regulatory agency with jurisdiction over the lease to recover part of its costs

d.It reimburses the Operator for its administrative costs

Bibliography

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CHAPTER 2

Well integrity basics

Chapter Outline

2.1. Terminology 16

2.1.1 Well life cycle 17

2.1.2 Well integrity in workovers and recompletions 18

2.1.3 New well integrity 19

2.2. Wellbore sketch 22

2.2.1 Planned well 22

2.2.2 As-built well 23

2.3. Barriers 24

2.3.1 Barrier element 25

2.3.2 Barrier envelope 27

2.3.3 Primary barrier 27

2.3.4 Secondary barrier 28

2.3.5 Barrier effectiveness 31

2.3.6 Barrier breach 31

2.3.7 Containment systems 34

2.4. Current well integrity 35

2.4.1 Newly drilled wells 35

2.4.2 Older wells 37

2.4.3 Newly acquired wells 37

2.4.4 Establishing/reestablishing baseline well integrity 37

2.5. Well integrity management system 40

Chapter Quiz 41

Bibliography 45

Abstract

This chapter introduces concepts involved in well integrity, in general, and mature well integrity for workovers and recompletions, in particular. Borehole stability while drilling and during well construction is a critical part of ensuring new well integrity. Also, of importance is the concept of continuous well integrity over the entire life-cycle of the well, from the basis of design through abandonment and beyond. A well must be capable of withstanding the workover or recompletion procedure, and provide a reliable conduit from the surface to the reservoir for some period of time following the work. Barrier elements and envelopes avoid fluid flow between zones downhole or to the environment. A good Well Integrity Management System is a key tool to ensuring continuous well integrity.

Keywords

Integrity; borehole stability; life-cycle; barrier element; barrier envelope; control; annulus; WIMS

The existence of oil was known as far back in antiquity as the construction of the Towers of Babylon, the walls of which were coated with pitch. Oil was used for fuel by the Chinese in the fourth century BC. The streets of Baghdad were paved with tar early in their construction. The Bible reports that pitch was used to waterproof the basket in which baby Moses was floated on the Nile River.

The Chinese began drilling wells using percussion tools and spring poles made from bamboo in the ninth century BC. The wells targeted brine accumulations, but oil was a byproduct. The oil was skimmed off and burned to heat and evaporate the brine. The first commercial oil fields were exploited near Baku, Azerbaijan in the tenth century AD. These shallow wells were dug by hand instead of being drilled.

The first commercial oil well was drilled using wooden rods on the coast of the Caspian Sea in July, 1847. The first well in the Western Hemisphere was drilled by American Merrimac Oil Company in the La Brea (Spanish for pitch) area of southwest Trinidad in 1857 to a depth of 280 ft. It was followed 2 years later in 1859 by the first commercial oil well in the United States drilled by Col. Edwin L. Drake on the banks of Oil Creek near Titusville, PA. Drake drilled his well using cable tools to a depth of 69 ft. In short, oil well exploitation through drilling has been around for a long time.

Well integrity, on the other hand, is a relatively new concept having only been introduced in the 1990s. Now, well integrity seems to permeate almost every discussion involving the basis of design (BOD), well design, construction, and well operations worldwide. It is also the subject of standards, specifications, and regulations.

In the last chapter, an attempt was made to define what was meant by the terms workover and recompletion. Other terms were defined to help the reader understand the economics and viability of each of these investment types. Here, more of the terms that apply to well integrity are discussed.

2.1 Terminology

Well integrity is one of those topics that may appear to be vague and somewhat confusing on the surface. Like the terms workover and recompletion, there does not appear to be a consensus on terminology associated with well integrity. This leads to lost time and energy until everyone in the orchestra starts reading from the same sheet of music.

Exactly what do we mean by the term well integrity? Is it some kind of moral or ethical personification of the well; does it have something to do with the well's character? Is it a term that defines the mechanical condition of a wellbore or some portion of it? How is this term used to describe a wellbore? All of these are fair questions for which there may, or may not, be good answers.

Obviously, wells are inanimate objects so personification is not valid. One well does not show greater moral character than another. So, the term integrity cannot apply to a well's ethics. Many of us experienced folks have been involved with wells that seem to take on human characteristics. Some are well behaved while others are troublesome and uncooperative, just like humans. Many folks tend to personify wells as a result of this behavior. In this discussion, the fact that a well behaves like a hard-to-manage stinker does not reflect on its integrity.

The goal of well integrity is to prevent the unexpected, unintended, and uncontrolled movement of fluids between geological horizons within the wellbore or to the environment at the surface. For our purposes, well integrity is the condition of the wellbore that creates a competent, integral (unbroken), fluid flow path directly connecting the hydrocarbon reservoir to the surface.

This definition involves many different parts of a well such as the casing, tubing, packer, cement sheath in the annulus between the casing and the borehole, the well head, tubing head, and tree valving. It does not include components downstream of the production tree such as the flowline, separation equipment, measurement equipment (meters), or pipelines.

The concept of well integrity involves flow barriers and the mechanical, operational, and management measures involved in thwarting leaks. Pressure in an annulus, or the lack thereof, may or may not be an indication of a leak. Thermally induced casing pressure may be present in a sealed annulus resulting from heating during production. An Operator may choose to maintain some level of pressure in an annulus to facilitate monitoring that annulus. Some types of artificial lift, such as gas lift, require Operator-imposed annular pressure.

2.1.1 Well life cycle

Well life cycle involves all the phases of a well from design and drilling through abandonment (and beyond) as described in International Standards Organization (ISO) 16530-1. The phases are important since they all impact a portion of the life cycle of the well. Further, knowledge about each phase assists in future operations, including the design and construction of new wells. So, there is both a forecast of future well integrity made possible through knowledge of the well's history and its expected future performance. Further, the well's performance influences the design and construction of new wells in the area (Fig. 2.1).

FIG. 2.1 Well integrity life cycle phases.

An important feature of this phase diagram is that all work on the well from initial well construction through operations and interventions of all kinds has a significant influence on well integrity in the abandonment phase. The better the barrier design and construction early in the life of the well, the higher the confidence in a successful life cycle and long-term abandonment.

Assume that a well has been producing from a sour, hydrogen sulfide (H2S)-laden, reservoir for much of its life with formation gas venting up the annulus. The probability of internal casing corrosion (usually pitting) might increase the risk of a casing failure during a workover if treatment fluids are pumped down the annulus and into the perforations. Equally as important are well construction failures in previous wells and the impacts these have on the design and construction of future wells. Experience in a field is often employed to bolster well construction and, consequently, future well integrity.

Case history 1:

The Coleman Junction is a shallow, sour (black water, H2S-ladened) aquifer underlying a significant portion of West Central Texas. Early wells penetrating the zone were cased using small-diameter pipe that also served as the production casing for deeper, productive reservoirs. The Coleman Junction is also a lost circulation zone. Most well casing strings were cemented just to the base of the Coleman Junction where the cement flowed out into the formation. This strategy avoided the cost of regaining circulation or spending considerably more money on the primary cement job than limited budgets allowed. New wells began production with good results, but almost exactly 1 year from the date of initial installation, casing leaks began, the result of external casing corrosion in the Coleman Junction. This resulted in expensive remedial cement work to repair the casing leaks.

These factors prompted Operators to first re-design their cement placement programs to ensure coverage of the Coleman Junction interval using a cement stage tool, or diverting valve (DV tool), located just above the top of the first-stage cement top inside the Coleman Junction interval (Fig. 2.2). This helped, but it did not eliminate all the casing leaks. Many Operators then changed their well design to include externally coated casing across the aquifer while others ran corrosion-resistant alloy casing through the Coleman Junction. Eventually, these design changes provided good well integrity in new wells that penetrated the Coleman Junction.

FIG. 2.2 Improved cement placement, Coleman Junction.

In a similar way, the original well design, well construction, initial completion, production/injection service, plus any workovers and recompletions performed during the well's life, have a pronounced impact on how a well must be securely plugged and abandoned. The well's history along with the environment to which it will be exposed following abandonment defines risks of leaks and emissions far beyond the well's usable life.

2.1.2 Well integrity in workovers and recompletions

Well integrity must be sufficient to withstand the rigors of the workover or recompletion procedure. It must also be sufficient to permit continued service for some period of time after the job. No prudent Operator would subject a well to forces beyond the capability of the well to withstand them during a workover, nor would one attempt a recompletion if the risk of well integrity failure was unacceptably high. Further, there must be some assurance of continued well life following the job for economic reasons.

The concept of reliability comes into play here. For older wells or wells that have suffered some type of damage in the past, reliability for future service becomes questionable following a strenuous, high-pressure workover or recompletion.

Well integrity is a time-dependent issue. A well that is not leaking today could develop a leak overnight. A casing string that could resist fracture pressure during high-rate pumping could collapse while the well is flowing back fracture fluids. Fortunately, there are diagnostic tools that can help to predict the reliability of the well for future service. Without some assurance of reliability for future service, justification of the cost of a workover or recompletion becomes difficult.

Reliability must be predicted based on the future service planned for the well. Past performance is no guarantee of future well integrity. For example, consider a well that has been producing sweet crude oil for two or three decades, then it is recompleted to a sour reservoir. Logically, the production casing will suffer more corrosion and possibly hydrogen embrittlement in the future. So, looking back at previous performance and well integrity will probably not provide an accurate prediction of future reliability. If the well is not properly equipped for sour gas service, it is not likely to be reliable for very long.

Reliability involves the risk. Risk is discussed more fully in later chapters, but it always involves an assessment of the consequences of unwanted leakage from the wellbore containment into some other downhole zone or the surface environment. Both outcomes are undesirable. One then must decide if the risk level is worth the value of future reserves that could be recovered from the well.

2.1.3 New well integrity

By definition, workovers and recompletions are performed on existing wells regardless of service life. Often, the wellbores are older having been produced from a reservoir for a considerable time. Well integrity issues differ between older wells and newly drilled and completed wells (again illustrating that well integrity is time-dependent). New wells have different objectives and well integrity issues.

Drilling

Well integrity while drilling a new wellbore involves the stability of the formation before casing is installed. In fact, this area of well integrity is often called borehole stability (BHS) to illustrate the notion that a hole drilled in newly exposed formations involves rock mechanics, natural stresses in the rock, and forces imposed during the drilling process.

Drilling involves the mechanical destruction of a portion of the rock matrix through pulverizing or shearing. This leaves a hole, or void, that advances forward (usually deeper) as the destruction process continues. Pressure from both the penetrated formation and that imposed by a mud column, or pressure applied at the surface to the newly drilled borehole, can add to natural stresses. Chemical forces from the drilling fluid and molecular changes involved in some formation types add to wellbore stress. Other forces, such as geomechanical stress on the formation being penetrated, complicate drilling. These can result in abrupt doglegs, pinched pipe at a reduced inside diameter (ID), and formation subsidence (bulk formation collapse).

There is considerable information available describing BHS in the literature, along with problems in drilling where BHS is poor. Sloughing shale is one example of poor BHS. This can be the result of chemical reactions between the drilling fluid, often water-based mud (WBM), and the shale causing the borehole to become unstable. Shale often detaches from the borehole wall and collapses into the well causing stuck pipe, excessive drag and torque, and poor hole cleaning. This can result in lost time and excessive costs to circulate the loose shale from the well. The final result is often an enlarged wellbore (i.e., a washout) that makes cement placement behind newly-installed casing difficult.

Another example involves drilling through salt. Here, the salt may already be under stress due to natural geomechanical forces. When the bit penetrates the salt, the stresses are partially relieved and the salt partially closes behind the bit in process known as pinching. The same process occurs while drilling tunnels through mountains due to the weight of the rock pressing downward on the newly drilled tunnel. The result is a restricted hole diameter just behind the bit that prevents it from being pulled up the hole for a connection, bit change, logging, changing out downhole tools, or other purposes. The effect of pinching is a tight hole ID, the opposite effect of shale sloughing which results in a hole enlargement.

BHS problems can impact final well construction and integrity. For example, if a shale section is only partially stable, the hole may remain open long enough to get casing into the hole. Sloughing due to poor BHS or from forces imposed while running the casing can cause the wellbore to slough before cement can be pumped into the annulus to stabilize the zone. This can ruin an otherwise high-quality cement job resulting in poor placement, the inability to rotate the casing or liner, and lost cement slurry pumped into productive reservoirs. Poor cement behind the pipe complicates future recompletion procedures and costs.

Creeping salt is the process by which a large salt body under geomechanical forces slowly distorts and flows. The salt behaves as a pseudoplastic, similar to very viscous toothpaste being squeezed out of a tube under tremendous force. If a well has been drilled through the salt body, this wholesale movement can buckle the cased wellbore. The same impact can be experienced when the well is located in an active fault zone. Obviously, the cement sheath behind the pipe is also adversely impacted due to the wellbore distortion in both cases.

In these failures, the casing distorts and then continues to buckle slowly until it is extremely difficult, if not impossible, to run or pull downhole tools, a work string, or production equipment below the damaged area. This eliminates some workovers and recompletion prospects. In extreme cases, the casing may collapse completely, or it can shear in two. Casing repairs are very difficult and expensive, and future wellbore reliability is questionable for wells that suffer this type damage. Abandonment may be the only option for these wells.

Initial completions

One economic objective for many Operators is to initially complete the new well in the best reservoir exposed during drilling, the so-called target zone. Production from, or injection into, this zone provides revenue to repay drilling costs, hopefully as quickly as possible. The rapid payout of the drilling and completion cash outlay improves the Operator's bottom line while also providing capital for other projects.

In the past, the Operator would initially complete in the deepest horizon penetrated by the wellbore. Once depleted, this zone was abandoned simply by plugging back inside the production casing. The next zone up the hole would then be completed (actually, recompleted) by perforating and treating the zone. It would be produced to depletion and plugged back to perforate the next productive zone, and so on up the hole, until all zones were systematically depleted, from bottom to top. Then, the well was permanently abandoned.

In recent years, the industry has evolved toward more rapid pay out of investments. The revenue from a newly completed zone is immediately rolled back into other investments, and the cycle is repeated with ever-increasing rapidity. The wells can be acquired by a larger Operator to increase their property portfolio, and the process repeats itself. This depletion method is often referred to as get in, get rich, and get out.

In this environment, the initial completion interval is often not the deepest one in the newly drilled well. Rather, the initial completion zone is the one that can yield the highest production flowrate to provide the highest cash flow and payout the initial cost of the well as quickly as possible. Injection wells are completed in the same interval to enhance production flowrates. Sadly, this can leave deeper, lower flowrate zones stranded below the initial completion interval. Recompleting to these intervals following depletion of the initial zone requires costlier procedures that may discourage the recompletion, thus lowering the well's ultimate reserve recovery. Operators with this new mentality often leave reserves behind the pipe in deeper

Reviews for Well Integrity for Workovers and Recompletions

[BoyBoy · Rating: 5 out of 5 stars]

Great book with Practical detail for both new hand or experienced