CHEN515:

PETROLEUM TECHNOLOGY
(UPSTREAM)

Lecture No.1:
PRODUCTION

Dr. Momoh Omuya Raheem

Room 55, PTDF Building
Email: omuyar2002@yahoo.com

February, 2017 1
Literature References
1. The Petroleum Handbook, 6th edition, compiled
by Staff of the Royal Dutch/Shell Group of
Companies. Elsevier 1983. Areas of
Concentration: Exploration and Production
(pp. 35-220).

2. Fundamentals of Reservoir Engineering by L.P.

Dake. Published by Elsevier Scientific
Publishing Co. New York, USA, 1978 or higher
edition. Areas of Concentration: Some Basic
Concepts in Reservoir Engineering (pp. 1-45).

3. Fundamentals of Petroleum by Kate Van Dyke,

4th edition. Published by Petroleum Extension
Services, Continuing & Extended Education.
The University of Texas at Austin; Austin,
Texas, USA, 1997. Areas of Concentration:
Course Presentations Outline
1. Literature References
2. Course Presentations Outline
3. Introduction/General Overview of Petroleum
Production
3.1 Definition
3.2 Early Production Methods
i. Completion
ii. Pumping
iii. Storage and handling
4. Modern Production Methods
4.1 Well Completion
iv. Production Casing and Liners
v. Open-hole, Perforated, Wire-wrapped Screen
Completion
4.1.1 Tubing and Packers
4.1.2 Well Head
4.1.3 Starting the Flows
5.1.1.1 Natural Drive
i. Water Drive
ii. Gas Drive (Dissolved Gas and Gas-cap)
iii. Combination Drives
iv. Gravity Drainage
5.1.2 Artificial Lift
v. Beam pumping
vi. Electrical submersible pumps
vii.Subsurface hydraulic pumps
viii.Gas lift
5.1.3 Well Testing
ix. Potential;
x. Bottom-hole pressure test
xi. Productivity test
xii.Wire-line formation test
5.1.4 Well Stimulation
xiii.Explosions
xiv.Hydraulic fracturing
xv.Proppants
iii. Fracturing fluid
5.1.5 Improved Recovery Techniques
5.1.5.1 Water flooding
iv. Injection water
5.1.5.2 Immiscible gas injection
5.1.5.3 Miscible gas injection
5.1.5.4 Chemical flooding
5.1.5.5 Thermal recovery
v. Steam drive
vi. Cyclic steam injection
vii.Fire flooding
6.1 Storage and Handling

Assignments
6.1.1 Surface Handling of Well Fluids
viii.Removing free water
ix. Separating liquids from gases
x. Treating oilfield emulsions
xi. Handling natural gases
 Assignments
6.1.2 Measuring and Testing Oil and Gas
6.1.3 Well Servicing and Workover
6.1.4 Transportation
i. Pipelines
ii. Ships at sea
iii. Trucks
iv. Railways
Lecture Presentations Outline
1. Introduction/General Overview of Petroleum
Production
1.1 Definition
1.2 Early Production Methods
i. Completion
ii. Pumping
iii. Storage and handling
2.0 Modern Production Methods
2.1 Well Completion
iv. Production Casing and Liners
v. Open-hole, Perforated, Wire-wrapped Screen
Completion
2.1.1 Tubing and Packers
2.1.2 Well Head
2.1.3 Starting the Flows
1. Introduction/General Overview of Petroleum
Production
1.1 Definition
In the petroleum industry, production is the
phase of operation that after drilling deals with
well completion, bringing the well fluids to the
surface (pumping), and preparing them for their
trip to the refinery or processing plant (handling
and transportation).

Other minor operations related to production

phase include:
i. Separation of the mixture of oil, gas, and
water after coming to the surface.
ii. Disposing of the water and
iii. Installation of series of equipment to treat or
purify, measure, and test the oil and gas
before they are transported away from the
wellsites.
1.2 Early Production Methods
The Chinese probably invented the earliest
methods of well completion. Historians believe
that they completed gas, water and saltwater
wells as early as 1000BC. Chinese technology
passed down through the centuries with few
changes, and it was not until the 1800s that the
innovation and inventiveness that mark the
production industry today began.

i. Completion
The present production era started in 1808
with a saltwater well that two brothers, David
and Ruffner, had dug in order to extract salt. To
extract more of the concentrated salt water from
the bottom of the well, the brothers decided that
running a pipe or tube (wrapped twine wood)
from the well bottom to the surface would seal
off water in the higher zones and prevent it from
 Figure 1: Running a pipe to line the sides o
well and sealing off the outside of the pipe
the bottom prevented Fluids from the form
near the tops from entering the well.

ii. Pumping
In the decade after Drakes discovery well in
1859, a cable-tool drilling rig remained on a well.
The walking beam on the rig that the driller used
to raise and drop the bit could later be adapted
to operate a reciprocating pump. In those days,
steam-driven equipment popularly called
iii. Storage and handling
The industry also had a problem with what to
do with the oil after it came out of the well.
Often wooden barrels were the only containers
available, and early operators used these for
collecting, storing, and shipping petroleum (Fig.
2). A barrel of crude, as it remains till date for
measuring petroleum, equals 42 gallons, or
0.1589 m3 (1m3 is 6.2897 bbls).
Later, earthen pits were used. Handling and
separation were difficult in any scale and became
even more when considerable amounts of water
and sand came mixed with the produced oil.
Tanks slowly replaced wooden barrels, first made
of wood, rivet iron , and finally bolted or welded
steel.
After 1920s, large advances were made in the
operation of lease facilities. Petroleum engineers
improved methods for oil, gas, and water
e 2: Wooden barrels were the first containers for
ng produced oils.
2.0 Modern Production Methods
In this lecture, the modern methods in
production exercise discusses the advancement
made compared with the techniques and
methods used in designing facilities for well
completion, pumping and handling/storage of oil
and gas in the modern times. It is hereby
presented as follows:

2.1 Well Completion

After a well has been drilled and the company
has determined that the reservoir will be
economical to produce, the work of setting the
final string of casing, preparing the well for
production, and bringing in the oil or gas begins.
Some of the equipment facilities and
operational measures required for well
completion are hereby discussed as follow:
 Another type of pipe that is not uncommon in
wells over 10,000ft (3,048m) is called a liner.
Usually, liner is like casing by function but does
not extend to the surface, which is sometimes a
considerable distance, the operator has a lower
pipe cost saved.

Figure 4: A production liner is ceme

In place but hangs from the bottom
Intermediate casing rather than ext
To the surface.
re 3: Conductor, surface, intermediate, and
uction casings are cemented in the well.
 Ii Open-hole, Perforated, Wire-wrapped
Screen Completion
The production casing either runs to the
bottom of the hole and blocks off the production
zone completely or rarely, stops just above the
production zone. If the casing stops above the
production zone and leaves the hole open, it is
an open hole or barefoot completion . The other
types of completion are depicted in Figures 6
through 8.

Figure 6: A perforated completion

ure 5: An open-hole completion
ows reservoir fluids into the uncased
 Figure 8: A wire-wrapped screen
ure 7: A wire-wrapped screen completion.
 2.1.1 Tubing and Packers

ure 9: Tubing is smaller in diameter

n casing.

Figure 10: A packer between the casing and

Keeps well fluids out of the casing-tubing an
Tubingless Completion
Although an operator will usually complete a
well with tubing, a small-diameter well that uses
small-diameter casing may be completed without
the tubing; this is tubingless completion. The
casing is cemented and perforated opposite the
producing zones (Fig. 11). Tubingless completion
are used mostly in small gas reservoirs that
produce few, if any liquids and low in pressure.

Figure 11: A tubingless completion ha

tubing string. Well fluids are produced
through small-diameter casing
Multiple Completions
The operator uses multiple completion when one
wellbore passes through many production zones
with oil and gas in them. For example, a triple
completion has three tubing strings and three
packers, and each zone produces independently
of the others.

Figure 12: A multiple production scheme.

2.1.2 Wellhead
The wellhead includes all equipment on the
surface that supports the various pipe strings,
seals off the well, and control the paths and flow
rates of reservoir fluids.
All wellheads have at least one casing head
and casing hanger, usually a tubing head and a
tubing hanger, and a Christmas tree.

Figure 13: A wellhead usually has one or more casing

a tubinghead and a Christmas tree.
2.1.3 Starting the Flow
As a well is drilled, pressure in the production
zone is offset by the pressure of the drilling fluid
in the hole. The drilling crew leaves this heavy
mud inside the casing after drilling is completed
so that its pressure will continue to offset the
formation pressure after the casing is
perforated. The completion crew usually runs
production tubing into the well while the drilling
fluid is still in place.
Means of reducing the pressure for formation
pressure to support certain production rate is
through washing in (pouring in of brine) and
swabbing (reduction of the brine).
Another means of starting production flow is
to force high-pressure gas into the tube before
setting the packer.
5.1 Pumping
Before well completion it is always very
necessary to estimate how much hydrocarbon
content does the reservoir contains as well as
the time it will take to exhaust all the contents.
Pumping in this regard is the means by how hc
content is displaced from a region of higher
pressure in its formation to a lower region at the
surface tank.
Therefore reservoir engineering is estimation of
hydrocarbon in place, the calculation of recovery
factor and the attachment of time scale to the
recovery.
This lecture will introduce through a simple
calculation, many of the fundamental concept of
reservoir engineering and similarly discuss
means by how hydrocarbon content can move
from the reservoir region to the surface.
Exercise1
The following data are available for a newly discovered
gas reservoir:
GWC = 9700ft
Centroid depth = 9537ft
Net bulk volume = 1.776 x 1010 ft3
Porosity, = 0.19
Saturation Connate Water Contact, Swc = 0.20
Gravity, g = 0.85

Although a gas sample was collected during a brief

production test the reservoir pressure was not recorded
because of tool failure. It is known , however that the
water pressure regime in the locality is:
Pw = 0.441D + 31 psia
and that the temperature gradient is 1.258oF/100ft,
with ambient surface temperature of 80oF.
1. Calculate the volume of the GIIP.
2. It is intended to enter a gas sales contract in which
the following points have been stipulated by the
purchaser.
a) During the two years, a production rate build up
from zero-100 MMscf/d (million) must be achieved while
developing the field;

b) The plateau rate must be continued for 15years at

sales point delivery which corresponds to minimum
reservoir pressure of 1200psia. Can this requirement be
fulfilled?

3. Once the market requirement can no longer be

satisfied, the field rate will decline exponentially by
20% per annum until it is reduced to 20 MMscf/d. (This
gas will either be used as fuel in the company
operational scheme or compressed to supply part of
a) In order to determine GIIP it is necessary to calculate
the initial gas pressure at the centroid depth of the
reservoir. That is, the depth at which there is as
much gas above as there is beneath, the pressures
for use in the material balance equation will always
be evaluated at this depth.

To do this the water pressure at the gas water contact

must first be calculated as:

and the temperature as

o
R

For this 0.85 gravity gas the isothermal Z- factor plot at

200 oF (662oR), Figure 1.8 can be used to determine the
Z-factor at the GWC, with negligible error. Thus
and the gas expansion,

The pressure gradient in the gas, at the GWC, can now

be calculated as:

The gas pressure at the centroid is therefore

and the absolute temperature at the centroid is

o
R
For the centroid pressure and temperature of 4290 psia
and oR respectively, the GIIP can be estimated as:
2)The overall production schedule can be divided into
three parts, the build-up, plateau production and the
decline periods as shown in Figure 1:
GP1
Rate, Q GP2 GP3
(MMCf/d)

Qo=100(MMCf/d)

50(MMCf/d)

20(MMCf/d)

t1 t2 t3

Figure 1: Gas field development rate-time schedule

Sincethe cumulative production during the two years

build up period is

then the gas production at the plateau rate of

100MMScf/d is:

and the time for which the plateau rate can be

maintained is:

Therefore, the time for which the plateau rate can be

sustained will fall short of the requirement some 2.5
yrs.

3) During the exponential decline period the rate at any

time after the start of the decline can be calculated as:

Where is the rate at t = 0, i.e., 100MMScf/d, and b is

If is the cumulative gas production at time t, measured
from the start of the decline, then

i.e.,

and when t = 8.05yrs,

Therefore, the total cumulative recovery at the

abandonment,

and the recovery factor

which will be recovered after a total period of

 This simple exercise covers the spectrum of
reservoir engineering activity, namely, estimating the
hydrocarbon in place, calculating a recovery factor and
attaching a time scale to the recovery. The latter is
imposed by the overall market rate required of the
field, i.e.,

Or,
5.1.1 Reservoir Drive Mechanisms (Reservoir
Engineering)