13304 PRODUCTION ENGINEERINGI Petroleum engineering Faculty of Exploration and Production Technology

13304

PRODUCTION ENGINEERING I

Petroleum engineering

Faculty of Exploration and Production Technology

Universitas Pertamina

OUTLINE

• Pressure drop through restriction

• Choke Performance

Pressure Drop Through Restriction

Surface or bottomhole chokes

The pressure drop across a surface choke can be eliminated to obtain the maximum producing capacity from a well while the losses occurring in SSSV’s and pipe fittings can not be avoided.

Subsurface safety valves (SSSV)

The purpose of a SSSV is not to control the flow rate, but to shut the well in when wellhead pressure becomes too low. Therefore, they are usually sized for minimum pressure drop and will be

operating in subcritical flow.

Valves and fittings

THE PRODUCTION SYSTEM

4

P_r PAY ZONE

WELL HEAD

WELL

SEPARATOR

LINE

P_wf P_up

P_down P_s

Pressure Drop Through Choke

Production Engineering I

CHOKE PERFORMANCE DEFINTION

• When the produced oil reaches the well-head choke, the well- head pressure is usually below the bubble-point pressure of the oil. As a consequence of that free gas exists in the fluid stream flowing through choke.

• The pressure loss accompanying the flow of oil, water, and gas

through a flow-line restriction (choke or bean) at the surface is

known as the CHOKE PERFORMANCE.

INTRODUCTION

• Placing a choke at the wellhead means fixing the wellhead pressure and, thus, the flowing bottom ‐ hole pressure and production rate.

• For a given wellhead pressure, by calculating pressure loss in

the tubing, the bottom hole pressure can be determined.

Why to use a choke?

• To limit and control the flowrate of the well

• To limit drawdown and avoid sand problems,

• To limit fluid velocity in the tubing (erosion)

• to avoid water or gas coning.

• To protect surface equipment from flow fluctuations,

• for regulations,

• To separate downstream (flowline) and upstream (well) parts of the production system.

• To absorb downstream pressure fluctuations without affecting the well

8

Choke at the Wellhead

• Reduced production rate to control water coning

• Control well production rate to meet

good engineering practice

TYPES OF WELLHEAD CHOKES

• Two types of wellhead chokes are used:

1.Positive (fixed) chokes 2.Adjustable chokes.

Positive or Fixed Choke

Whereby the orifice size is specified before installation. This normally consists of two parts:

• A choke which consists of a machined housing into which the orifice capability or "bean" is installed.

• A "bean" which consists of a short length 1-6", of thick walled tube with a smooth, machined bore of specified size.

Fixed chokes are occasionally installed in wireline nipples at depth in the tubing string in certain wells to:

• Reduce the tubing head pressure and operating pressures on the Xmas tree and wellhead

• Counteract the effects of hydrates and wax deposition associated with fluid expansion and cooling. The location of cooling is moved down into the tubing string where the fluid can extract heat from the surrounding formation as it flows to surface.

ADJUSTABLE CHOKES

• Whereby the orifice size can be adjusted after installation to suit the well and operational

requirements

• In this design, the choke is normally located on a 90°

bend. The orifice consists of a valve seat into which a valve stem can be inserted and retracted, thus

adjusting the orifice size.

• The movement of the valve stem can either be

manual as shown in Figure 33 or automatic using an hydraulic or electrohydraulic controller.

Well Head: the choke

13

up Down

P r = P

A choke is an equipment that places a restriction in the flow line.

Parameters:

- P_up = Pressure upstream the choke

- P_down = Pressure downstream the choke

- r = ratio between pressures upstream and downstream - A = area of flow (often given in 64^th of inches)

- D₁ = diameter of the choke throat - D₂ = diameter of the line

P_up D₁ D₂ P_down

Flow in Choke

• The fluid flow pattern through the choke is shown on the left figure. The choke gives an abrupt

changes in diameter, and yield restriction to the flow.

• This restriction produce high velocity inside the restriction, therefore it will decrease the pressure in the centre of the choke. This situation is called as the “Vena Contracta”.

• As shown in the figure, the liquid is forced to flow through a smaller diameter and then in a very short distance the fluid expands again to its original diameter.

• The decrease in velocity results in recovery of (some) of the pressure that had been lost during passage through the choke. Full pressure

recovery is not normally experienced since there are irreversible pressure losses due to eddy

currents which create disengagement and

reattachment of the flowlines to the pipeline wall.

Sonic Subsonic FLow

• Pressure drop across well chokes is usually very significant. There is no universal equation for predicting pressure drop across the chokes for all types of production fluids.

• Different choke flow models are available from the literature, and they have to be chosen based on the gas fraction in the fluid and flow regimes, that is, subsonic or sonic flow.

• When the fluid flow velocity in a choke reaches the traveling velocity of sound in the fluid under the in situ condition, the flow is called ‘‘sonic flow.’’ Under sonic flow conditions, the pressure wave downstream of the choke cannot go upstream through the choke because the medium (fluid) is traveling in the opposite direction at the same velocity.

Sonic Subsonic FLow

• A sonic flow exists at a choke depends on a downstream-to- upstream pressure ratio. If this pressure ratio is less than a critical pressure ratio, sonic (critical) flow exists. If this pressure ratio is greater than or equal to the critical pressure ratio, subsonic (subcritical) flow exists.

• The critical pressure ratio through chokes is expressed as:

Qualitative behaviour of the choke

17

if r < r_c, the choke regulates flowrate in relation to

downstream pressure variations

→ q= cte

r_c ¹

critical flow

q

Critical flow is obtained when the fluid is sufficiently accelerated to reach sonic velocity in the choke throat.

r_c0.55 (gas) ; r_c> 0.55 (oil)

sub-critical flow

P 

if r < r_c, the choke controls the flow rate:

q≠ cte

P_up ^{D1 D2 Pdown }

P_up, D₁ and D₂ fixed P_down varies

Single-phase Liquid Flow

P_up ^{D1 D2 Pdown }

• For single-phase liquid flow, kinetic energy change across a choke

𝑞 = 𝐶𝐷𝐴 2𝑔𝑐∆𝑃 𝜌 q: flow rate, ft3/s

C_D: choke discharge coefficient A: choke area, ft2

g_c: unit conversion factor, 32.17 lbm-ft/lbf-s2 ΔP: pressure drop, lbf/ft2

ρ: fluid density, lbm/ft3

𝑃 𝑜𝑢𝑡𝑙𝑒𝑡

𝑃 𝑢𝑝 = 2 𝐾 + 1

𝑘 𝑘−1

In field units:

𝑞 = 8074𝐶𝐷𝑑₂² ∆𝑃 𝜌 q: flow rate, bbl/d

D2: choke diameter, in ΔP: pressure drop, psi

Determine Choke Discharge Coefficient

𝐶_𝐷 = ^𝑑2

𝑑1+ ^0.3167_𝑑2

𝑑1

0.6 + 0.025[log 𝑁_𝑅𝑒 − 4]

d1: upstream pipe diameter, in d2: choke diameter, in

N_Re: Reynold number based on d2

nozzle

orifice

Single-phase Gas Flow

Subsonic flow

𝑞

_𝑆𝐶

= 1248𝐶

_𝐷

𝐴

₂

𝑃

_𝑢𝑝

𝑘

(𝑘 − 1)𝛾

_𝑔

𝑇

_𝑢𝑝

𝑃

_𝑑𝑛

𝑃

_𝑢𝑝

2 𝑘

− 𝑃

_𝑑𝑛

𝑃

_𝑢𝑝

𝑘+1 𝑘

Q sc: gas flow rate, Mscf/d

Pup: upstream pressure at choke, psia A2: cross-sectional area of choke, in2 Tup: uptream temperature, R

g: acceleration of gravity, 32.2 ft/s2

ϒg: Gas-specific gravity related to air

Single-phase Gas Flow Subsonic flow

Determine C

_D

𝑁

_𝑅𝑒

= 20𝑞

_𝑠𝑐

𝛾

_𝑔

𝜇𝑑

₂

𝜇: gas viscosity in cp

Gas velocity under subsonic flow condition is less than the sound velocity in gas at th in situ:

𝑣 = 𝑣

_𝑢𝑝²

+ 2𝑔

_𝑐

𝐶

_𝑝

𝑇

_𝑢𝑝

1 − 𝑧

_𝑢𝑝

𝑧

_𝑑𝑛

𝑃

_{𝑑𝑜𝑤𝑛}

𝑃

_𝑢𝑝

𝑘−1 𝑘

Cp: specific heat of gas at constrant pressure (187.7 lbf-ft/lbm-R for

air)

Single-phase Gas Flow

Sonic flow

Equation for ideal gas:

𝑞

_𝑆𝐶

= 879𝐶

_𝐷

𝐴

₂

𝑃

_𝑢𝑝

𝑘 𝛾

_𝑔

𝑇

_𝑢𝑝

2 𝑘 + 1

𝑘+1 𝑘−1

Q sc: gas flow rate, Mscf/d

Pup: upstream pressure at choke, psia A2: cross-sectional area of choke, in2 Tup: uptream temperature, R

g: acceleration of gravity, 32.2 ft/s2

ϒg: Gas-specific gravity related to air

Single-phase Gas Flow Sonic flow

Determine C

_D

𝑁

_𝑅𝑒

= 20𝑞

_𝑠𝑐

𝛾

_𝑔

𝜇𝑑

₂

𝜇: gas viscosity in cp

Gas velocity under sonic flow condition is equal the sound velocity in gas at th in situ:

𝑣 = 𝑣

_𝑢𝑝²

+ 2𝑔

_𝑐

𝐶

_𝑝

𝑇

_𝑢𝑝

1 − 𝑧

_𝑢𝑝

𝑧

_𝑑𝑛

2

𝑘 + 1 𝑜𝑟 𝑣 ≈ 44.76 𝑇

_𝑢𝑝

Cp: specific heat of gas at constrant pressure (187.7 lbf-ft/lbm-R for

air)

SUMMARY – Single phase flow

Liquid Gas

Flowrate:

𝑞 = 8074𝐶𝐷𝑑₂² ∆𝑃 𝜌

Subsonic Flow:

𝑞_𝑆𝐶 = 1248𝐶_𝐷𝐴₂𝑃_𝑢𝑝 𝑘

(𝑘 − 1)𝛾_𝑔𝑇_𝑢𝑝

𝑃_𝑑𝑛 𝑃_𝑢𝑝

2 𝑘

− 𝑃_𝑑𝑛 𝑃_𝑢𝑝

𝑘+1 𝑘

Sonic Flow:

𝑞_𝑆𝐶 = 879𝐶_𝐷𝐴₂𝑃_𝑢𝑝 𝑘 𝛾_𝑔𝑇_𝑢𝑝

2 𝑘 + 1

𝑘+1 𝑘−1

Critical pressure ratio

through choke:

Temperature at choke

• Assuming an isentropic process for an ideal gas flowing trough chokes,

𝑇

_𝑑𝑛

= 𝑇

_𝑢𝑝

𝑧

_𝑢𝑝

𝑧

_{𝑜𝑢𝑡𝑙𝑒𝑡}

𝑃

_{𝑜𝑢𝑡𝑙𝑒𝑡}

𝑃

_𝑢𝑝

𝑘−1 𝑘

The outlet pressure is equal to the downstream pressure in

subsonic flow conditions

Exercise 1

• A 0.6 specific gravity gas flows from a 2-in. pipe through a 1-in.

orifice-type choke. The upstream pressure and temperature are 800 psia and 75

^o

F, respectively. The downstream pressure is 200 psia (measured 2 ft from the orifice). The gas-specific heat ratio is 1.3

(a) What is the expected daily flow rate?

(b) Does heating need to be applied to ensure that the frost does not clog the orifice?

(c) What is the expected pressure at the orifice outlet?

𝑁_𝑅𝑒 = 20𝑞_𝑠𝑐𝛾_𝑔 𝜇𝑑₂

Solution

(a) Expected daily flowrate

𝑝 _{𝑑𝑜𝑤𝑛} 𝑃 _𝑢𝑝

=

Nre assumed 10^6 → C

_D

= ??

𝑞

_𝑆𝐶

= 879𝐶

_𝐷

𝐴

₂

𝑃

_𝑢𝑝

𝑘 𝛾

_𝑔

𝑇

_𝑢𝑝

2 𝑘 + 1

𝑘+1 𝑘−1

orifice

Solution

(b) Heating needed to be applied?

𝑇

_𝑑𝑛

= 𝑇

_𝑢𝑝

𝑧

_𝑢𝑝

𝑧

_{𝑜𝑢𝑡𝑙𝑒𝑡}

𝑃

_{𝑜𝑢𝑡𝑙𝑒𝑡}

𝑃

_𝑢𝑝

𝑘−1 𝑘

(c) Expected pressure at orifice outlet

P outlet =

Exercise 2

A 0.65 specific gravity natural gas flows from a 2-in. pipe through a 1.5-in.

nozzle-type choke. The upstream pressure and temperature are 100 psia and 70

^o

F, respectively. The downstream pressure is 80 psia (measured 2 ft from the nozzle). The gas-specific heat ratio is 1.25.

(a) What is the expected daily flow rate?

(b) Is icing a potential problem?

(c) What is the expected pressure at the nozzle outlet?

MULTIPHASE FLOW THROUGH A CHOKE

• A number of researches have published studies on multiphase flow through chokes.

• Some of the studies relate to correlation of field measurement. Several empirical choke flow models have been developed in the past half. They generally take the following form for sonic flow:

where:

P_u = the upstream pressure (psig, except for Ros who uses the unit psia) Q_L = the liquid critical flow rate (Stb/d)

D₆₄ = the choke diameter (64th of an inch) R = the gas / liquid ratio (scf/STB) and a,b, & c = are constants

• In the wellhead, P_u is wellhead pressure

𝑃 𝑢 = 𝑏𝑄𝑅

^𝐶

𝐷 64

^𝑎

Multiphase Flow critical Condition (Sonic Flow)

Exercise 3

1)Using both the Ros and Gilbert equations, determine the

choke size required to obtain a liquid rate of 400 STB/day a wellhead pressure is 900 psia and R = 600 scf/STB.

2) A well is producing 100 bbl/day gross with GLR of 700 ft³/bbl. If the bean size is ¼ in, calculate THP?

3) A well is producing 40 API oil at 200 stb/d and no gas. If the beam size is 1 in., pipe size is 2 in., temperature is 100

^o

F,

estimate pressure drop across a nozzle-type choke.

Choke Correlations in Multiphase

• Multiphase Flow Subcritical Condition (Subsonic Flow)

CHOKE SIZE ANALYSIS

• The effect of choke size on the flow rate and wellhead pressure at constant gas/liquid ratio is shown in the figure of next slide.

• When the choke size increases both wellhead pressure and liquid rate will increase until to the point. Whereas, any further increasing in the choke size the liquid rate will increase but wellhead pressure reduces.

• In extreme reduction of choke size, the gas will liberate causing

increasing the bottom hole pressure, consequently, the wellhead

pressure will fall down.

EFFECT OF CHOKE SIZE ON THE LIQUID

RATE

Choke behaviour: example

choke behaviour

0 2000 4000 6000 8000 10000 12000 14000

0 0.2 0.4 0.6 0.8 1 1.2

r = Pdown/Pup

liquid rate (bbl/d)

diam = 1.2"

diam = 1.4"

diam = 1.8"

diam = 2"

36

Example:

oil well

GOR = 1100 scf/STB P_up = 30 BARa

r_c

For example, to obtain 6300 stb/d, we can choose between:

- diam regulation to 1.4" (corresponds to the critical rate = 6300bbl/d), and r < rc - diam fixed to 1.8", and r regulation, higher than r_c

KEY POINTS TO KEEP IN MIND

38

The well head choke allows to limit and control the production rate.

A fluid flowing through a choke can be in the critical regime (i.e.fluid velocity corresponds to sound velocity) or sub-critical regime.

The critical ratio of the choke (r_c) is equal to the pressure ratio P_down/P_{up .}It corresponds to the transition between critical and sub-critical regimes.

The choke isolates the well (upstream) from the flowline (downstream)

From wellhead to the separator

In the critical flow regime (i.e. below r_c), the flowrate remains constant even if the pressure ratio changes.