** PL3. COMPLETION DESIGN**

**4. CORE ANALYSIS Reference 1. The Completion engineer should check the availability of formation**

**4.8. Reduction of permeability during production**

**4.8.1.** Obstructions may occur also during production phase and caused by
the following.

**4.8.2.** Produced fines.

**4.8.3.** Scales.

**4.8.4.** Asphaltenes.

**5. STRATEGY TO MINIMISE THE SKIN EFFECTS** ^{Reference}

**5.1.** In a radial flow situation, where fluids move towards the well from all
directions, most of the pressure drop in the reservoir occurs fairly
close to the wellbore. In a uniform sand, the pressure drop across the
last 15ft of the formation surrounding the wellbore is about one half of
the total pressure drop from the well to a point 500ft away in the
reservoir. Obviously flow velocities increase tremendously as fluid
approaches the wellbore. This area around the wellbore is the ‘critical
area’ and as much as possible should be done to prevent damage or
flow restrictions in this critical area.

P-1-M-7100 2.2.6

**5.2.** If a well is to be perforated overbalanced, then strict control over the
fluid used to ensure it is compatible with the reservoir formation,
formation fluids and must also be clean to prevent formation damage.

P-1-M-7100 9.3.1

**5.3.** Phasing ^{P-1-M-7100} ^{9.3.1}

**5.4.** Gun stand-off ^{P-1-M-7100} ^{9.3.1}

**5.5.** Use of clean tubular goods.

**5.6.** Maximise the perforated zone within the net pay. ^{P-1-M-7100} ^{9.3.1}
**5.7.** Use of underbalance perforating practice. ^{P-1-M-7100} ^{9.3.2}

**5.8.** Use of maximum shot density. ^{P-1-M-7100} ^{9.3.1}

**5.9.** Perforating tunnels should be large and deep enough to prevent any
restriction to flow.

P-1-M-7100 2.2.6

**5.10.** Gravel Pack Completions

Due to the problem of flow restriction the important factors are:

• Hole diameter to achieve adequate flow area.

• Shot density to achieve adequate flow area.

• Debris removal.

• Shot phasing.

• Penetration.

This in conjunction with correct gravel pack procedures is essential for to prevent high skin factors.

P-1-M-7100 9.3.1

**5.11.** Specific chemical treating of the near wellbore area to remove
formation damage.

**5.12.** Limit brine volume losses in depleted reservoir and use surface
tension reducer.

**6. WELL INFLOW PERFORMANCE** ^{Reference}

**6.1.** The inflow performance relationship (IPR) provides the flow potential
of the reservoir into the wellbore against the resistance to flow of the
formation and near wellbore region. The theoretical IPR is an
idealistic assumption of flow performance without pressure drop due
to skin effect in the near wellbore region and governed only by the
size, shape and permeability of the producing zone and the properties
of the produced fluids.

P-1-M-7100 2.4

**6.2.** The equation used shall take into account all the Darcy and
non-Darcy effects.

**6.3.** Where inflow relationship passes through the bubble point, a straight
line IPR is drawn above the bubble point and the curved IPR signifies
the two phase flow below this point. For this, Vogel’s equation is
combined with the PI to develop a general IPR equation. This has
been published by Brown. When the BHFP is above the bubble point
use the normal straight line equation:

### (

R wf### )

o Jp p

q = −

and when it drops below the bubble point use the modified Vogel equation:

**6.4.** Fetkovich recognised that many oil wells could be handled in the
same way as gas wells using the curved IPR:

### (

^{R}

^{2}

^{wf}

^{2}

### )

^{n}

o Cp p

q = −

where:

C = Linear deliverability coefficient n = Deliverability exponent (0.5 to 1.0)

P-1-M-7100 2.4.1

**6.5.** Blount and Jones presented an alternative generalised IPR equation
which was an extension to the Forcheimer equation to include the
non-Darcy flow effects:

2 wf

R p aq bq

p − = +

P-1-M-7100 2.4.1

**6.6.** Forcheimer equation for gas wells should be used for pressure below
2,000psi and where the drawdown is small as in high permeability
wells:

2 g g wf

R p Aq Aq

p − = +

P-1-M-7100 2.4.1

**6.7.** When the µz value is not constant the pseudo pressure m(p) shall be
used instead of P².

Pseudo pressure m(p) shall be used when pressure is above 2,000psi and in low permeability wells where drawdown greater than 500psi is expected.

**Reference List:**

‘Completion Design Manual’ STAP-P-1-M-7100

**Figure PL 3.3 - Reservoir Pressure Trends For Various Drive Mechanisms**

**Figure PL 3.4 - Gas-Oil Ratios Trends For Various Drive Mechanisms**

**PL. 3.5. ** **TUBING PERFORMANCE**

**1. GENERAL** ^{Reference}

**1.1.** The relationship between pressure and temperature drop in wells and
PVT behaviour is complex. Pressure drop is determined using
empirical and semi-empirical correlation’s and carried out on
computer software programmes.

P-1-M-7100 2.4.4

**1.2.** Calculating pressure drop in tubing involve numerical integration of
the steady-state pressure gradient equation over the entire tubing
length. It consists of the following three components:

• Hydrostatic head

• Wall friction

• Fluid acceleration.

P-1-M-7100 2.4.4

**1.3.** The acceleration term is usually negligible except in system involving
significant fluid expansion (gas wells when near atmospheric
pressure).

P-1-M-7100 2.4.4

**1.4.** The friction losses are controlled by fluid viscosity and geometric
factor (pipe diameter and roughness) and normally accounts for
around 10 % of overall head losses.

P-1-M-7100 2.4.4

**1.5.** The gravitational component accounts for around 90 % of the overall
head losses and is proportional to the density of the fluid mixture at
each point in the tubing and is a complex function of the relative
velocity of the phases present.

P-1-M-7100 2.4.4

**1.6.** The geometrical distribution of the gas and liquid in the pipe
constitute the “flow pattern” or “flow regime”. The flow patterns are
governed by the flow rates of each phase, the tubing diameter and to
a lesser extent PVT fluid properties.

P-1-M-7100 2.4.4

**1.7.** Flow patterns are identified using empirical flow pattern maps. Each
flow regime has different pressure gradients that should be calculated
by the use of different empirical correlation for liquid hold-up and
friction factor.

**1.8.** Typical pressure gradients in wells for different flow patterns are:

• Single phase oil = 0.36psi/ft

• Bubble flow = 0.25psi/ft

• Slug flow = 0.20psi/ft

• Mist flow = 0.1 - 0.2psi/ft

P-1-M-7100 2.4.4

**2. TEMPERATURE GRADIENT** ^{Reference}