well completion introduction

Well completion introduction

The scope of completions is broad. This book aims to cover all the major
considerations for completions, from the near wellbore to the interface with
facilities. The intent is to provide guidance for all those who use or interface with
completions, from reservoir and drilling engineers through petroleum and
completion engineers to production and facilities engineers.
The book focuses on the design of completions starting from low-rate land wells
to highly sophisticated deepwater subsea smart wells with stimulation and sand
control, covering most options in between. There is no regional focus, so it is
inevitable that some specialised techniques will be glossed over. To be applicable to a
wide audience, vendor specifics have been excluded where possible.

1-What are Completions?

Completions are the interface between the reservoir and surface production.
The role of the completion designer is to take a well that has been drilled and
convert it into a safe and efficient production or injection conduit. This does not
mean that the completion always has tubing, a Christmas tree or any other piece of
equipment. In some areas, it may, for example, be possible to produce open hole
and then up the casing. However, as we venture into more hostile areas such as
deepwater or the arctic, the challenges mount and completions, by necessity,
become more complex.
Completion design is a mix of physics, chemistry, mathematics, engineering,
geology, hydraulics, material science and practical hands-on wellsite experience.
The best completion engineers will be able to balance the theoretical with the
practical. However, there is a strong role for those who prefer the more theoretical
aspects. Conversely, an engineer who can manage contracts, logistics, multiple
service companies, the detailed workings of specialised pieces of equipment and a
crew of 50 is invaluable. Some completion engineers work on contract or directly
with the oil and gas companies. Other engineers work with the service companies,
and a detailed knowledge of their own equipment is invaluable.

2-. Safety and Environment

Safety is critical in completions; people have been killed by poorly designed or
poorly installed completions. The completion must be designed so as to be safely
installed and operated. Safe installation will need to reference hazards such as well
control, heavy lifts, chemicals and simultaneous operations. 

 Safe operation is primarily about maintaining well
integrity and sufficient barriers throughout the well life. This section focuses on
design safety.
It is common practice to perform risk assessments for all well operations. These
should be ingrained into the completion design. The risk assessments should not
just cover the installation procedures but also try to identify any risk to the
completion that has a safety, environmental or business impact. Once risks are
identified, they are categorised according to their impact and likelihood as shown in
Figure . Most companies have their own procedures for risk assessments,
defining the impact in terms of injuries, leak potential, cost, etc., and likelihood in
terms of a defined frequency. Mitigation methods need to be identified and put in
place for any risk in the red category and ideally for other risks. Mitigation of a risk
should have a single person assigned the responsibility and a timeline for
investigation. It is easy to approach risk assessments as a mechanical tick in the
box procedure required to satisfy a company’s policy; however, when done properly
and with the right people, they are a useful tool for thinking about risk. Sometimes,
risks need to be quantified further and numerically. Quantitative Risk Assessments
(QRAs) attempt to evaluate the risk in terms of cost versus benefit. QRAs are
particularly useful for decisions regarding adding or removing safety-related
equipment. Clearly, additional expertise with completion engineering is required
for these assessments. Such expertise can assist in quantifying the effect of leaks,
fires, explosions, etc., on people, nearby facilities and the environment.
Example – annular safety valves
Annular safety valves are used to reduce the consequence of a major incident on a
platform with gas lift. They are designed to fail close and lock in a significant
inventory of lift gas in the annulus. The probability of such a major incident can be
estimated, as can the consequences of the escape of the entire annular inventory of lift
gas (fire size, duration, and impact on people and other processes). Installing annular
safety valves will not alter the probability of a major platform incident but will reduce
the consequences (smaller fire). However, annular safety valves do not shut
instantaneously, they might not always work and their installation adds both cost
and additional risks. What do you do if the annular safety valve fails in the open
position? Do you replace it (at additional cost and risk)? What do you do if the valve
fails in the (more likely) closed position? Quantifying possible outcomes can help
determine the optimum choice. Note that I am not making a stance in either
direction; the decision to install an annular safety valve depends on the probabilities
and consequences. Where both effect and probability are moderate (e.g. a deepwater
subsea well), the value in terms of safety of such a valve is considerably lower than for a
densely populated platform with multiple, deep, high-pressure gas lift wells.

1. Well control and barriers

Completions are usually part of the well control envelope and remain so through
the life of the well. They are part of the fundamental barrier system between the
reservoir and the environment. Although definitions will vary from company to
company, a simple rule in well control is as follows. ‘At least two tested independent
barriers between hydrocarbons in the reservoir and the environment at all times’.
The barriers do not necessarily need to be mechanical barriers such as tubing; they
can include mud whilst drilling or the off switch of a pumped well. Examples of
barriers during various phases of well construction and operation are shown in
the following table.
The primary barrier is defined here as the barrier that initially prevents
hydrocarbons from escaping; for example, the mud, the tubing or the Christmas
tree. The secondary barrier is defined as the backup to the primary barrier – it is not




 normally in use until the primary barrier fails. The secondary barrier must be
independent of the primary barrier, that is, any event that could destroy the
primary barrier should not affect the secondary barrier. For example, when
pulling the blowout preventer (BOP), a deep-set plug and kill weight brine do
not constitute two independent barriers. The loss of integrity of the plug
could cause the kill weight fluid to leak away.
As part of the well design, it is worthwhile drawing the barriers at each stage of a
well’s life. This is recommended by the Norwegian standard NORSOK D-010
(Norsok D010, 2004) where they are called well barrier schematics (WBS). An
example is shown  for a naturally flowing well. How the barriers were
tested and how they are maintained should also be included.
Note that some barriers are hard to pressure test, particularly cement behind
casing. Additional assurances that cement provides an effective barrier are the
volume of cement pumped, cement bond logs and, for many platform and land
wells, annulus monitoring. For subsea wells and some tie-back wells, annulus
monitoring is not possible except for the tubing – casing annulus.
Ideally, pressure testing should be in the direction of a potential leak, for
example, pressure testing the tubing. Sometimes this is not practical. If there is
anything (valve openings, corrosion, erosion, turbulence, scale, etc.) that can affect a
barrier then the barrier should be tested periodically. This applies to the primary
barriers and often to the secondary barriers as well (e.g. safety valve).
2- Environmental protection
Completions affect the environment. Sometimes this is for the worse, and
occasionally for the better.  The design of completions has a much greater environmental
effect.
1. An efficient completion improves production but also reduces the energy
consumption (and associated emissions) required to get hydrocarbons out of the
ground.
2. Well-designed completions can reduce the production of waste materials by
being able to control water or gas production.
3. Completions can be designed to handle waste product reinjection, for example
drill cuttings, produced water, non-exported gas, sulphur or sour fluids.
Sometimes this disposal can be achieved without dedicated wells. .
4. Carbon capture and sequestration will likely become a big industry. Carbon
sequestration may not be associated with oil and gas developments, for example
injection of carbon dioxide from a coal power station into a nearby saline aquifer.
Carbon sequestration may also involve active or decommissioned oil and gas
reservoirs. Regardless, sequestration requires completions.

 The Role of the Completion Engineer

Completion engineers must function as part of a team. Although a field
development team will consist of many people, some of the critical interactions are
identified in the following figure .
I have placed completion engineers at the centre of this diagram, not because
they are more important than anyone else but because they probably need to
interact with more people. As completions are the interface between reservoir and
facilities, completion engineers need to understand both. Many teams are further
subdivided into a subsurface team, a facilities team and a drilling team. Which subteam
the completions engineers are part of varies. Completion engineers are often
part of the drilling team. In some companies, completion design is not a separate
discipline but a role performed by drilling engineers. In some other companies, it is
part of a petroleum engineering discipline sub-group that includes reservoir
engineering, petrophysics and well operations. To a large extent, how the overall
field development team is split up does not really matter, so long as the tasks are
done in a timely manner and issues are communicated between disciplines.
The timing of completion engineering involvement does matter – in particular,
they need to be involved early in the field development plan. Completion design
can have a large effect on facilities design (e.g. artificial lift requirements such as
power). Completions have a large effect on the drilling design (e.g. hole and casing
size and well trajectory). They also influence well numbers, well locations and
production profiles. Unfortunately, in my experience, completion designers are
brought into the planning of fields at too late a stage. A field development team
involved at the starting point comprises a geologist, geophysicist, reservoir engineer,
drilling engineer and facilities engineer. By the time a completion engineer joins a
team (along with many others), well locations and casing sizes are already decided
and some aspects of the facilities agreed upon, such as throughput, processing and

 export routes. So all a completion engineer has to do is fit the completion into the
casing and produce the fluid to a given surface pressure. Many opportunities for
improvement are lost this way.
A vital role of completion engineers is to work with the service sector. The
service sector will normally supply the drilling rig, services (wireline, filtration,
etc.), equipment (tubing, completion equipment, etc.), consumables (brine,
proppant, chemicals, etc.) and rental equipment. Importantly, the service sector
will provide the majority of people who do the actual work. Inevitably, there will be
multiple service companies involved, all hopefully fully conversant with their own
products. A critical role of the completion engineer is to identify and manage these
interfaces personally, and not to leave it to others.
For small projects, a single completion engineer supported by service companies
and specialists is often sufficient. Ideally, the completion engineer designs the
completion, coordinates equipment and services and then goes to the wellsite to
oversee the completion installation. The engineer then writes the post-job report. If
one individual designs the completion and another installs it, then a good interface
is needed between these engineers. A recipe for a poor outcome is a completion
designer with little operational experience and a completion installer who only gets
involved at the last minute.
For large projects, the completion design may be distributed to more than one
engineer. There may be an engineer concentrating on the reservoir completion (e.g.
sand control), another concentrating on the upper completion (e.g. artificial lift) and
possibly a number of them concentrating on installing the completion. Such an
arrangement is fine so long as someone is coordinating efforts and looking at the
wider issues.
A point of debate in many teams employing dedicated completion engineers is
where the drilling ends and completions begin. This frequently depends on the type
of completion. My recommendations are:
1- For cased and perforated wells, the completion begins once the casing/liner hasbeen cemented. This means that the completion engineer is responsible for the
mud displacement and wellbore clean-out – with the assistance of the drilling
engineer.
 2-For open hole completions, the completion begins once the reservoir section has
been drilled and the drill string pulled out. The overlap such as mud conditioning
or displacement must be carefully managed.