nodal analysis, well problem analysis, wax

Nodal Analysis, Well Problem

Analysis, Wax and Sand Control

Sanjay K. Dhiraj Dy. SRE, G&R Deptt.

Objectives

Understand the components of Inflow

performance

Understand the components of vertical

lift performance

Understand combining inflow and vertical

lift performance

Wax problem analysis

Sand problem analysis

INJECTION GAS

PRODUCED FLUID

WELL

INFLOW (IPR)

WELL OUTFLOW

RELATIONSHIP

(VLP)

SURFACE PRESSURE

SANDFACE

PRESSURE

BHFP

RESERVOIR

PRESSURE

BOTTOM HOLE PRESSURE AS A FUNCTION OF FLOWRATE

PRODUCTION POTENTIAL AS A FUNCTION OF PRODUCTION RATE

P e

_

P r P wfs P wf

P dr

P ur

P usv

P dsv

P wh

P dsc P sep

D P 1 = P r - P wfs = Loss in Porous Medium

D P 2 = P wfs - P wf = Loss across Completion

D P 3 = P ur - P dr = Loss across Restriction

D P 4 = P usv - P dsv = Loss across Safety Valve

D P 5 = P wh - P dsc = Loss across Surface Choke

D P 6 = P dsc - P sep = Loss in Flowline

D P 7 = P wf - P wh = Total Loss in Tubing

D P 8 = P wh - P sep = Total Loss in Flowline

Possible Pressure Losses in Complete Production System

Bottom

Hole

Restriction

Safety

Valve

Surface

Choke

Separator

Pressure Losses

Inflow Performance Curve

0

500

1000

1500

2000

2500

3000

3500

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Production rate, STB/D

Flo

win

g b

ott

om

ho

le p

ressu

re, p

si

Inflow (Reservoir) Curve

Tubing Curve

0

500

1000

1500

2000

2500

3000

3500

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Production rate, STB/D

Flo

win

g b

ott

om

ho

le p

ressu

re, p

si

Tubing Curve

0

500

1000

1500

2000

2500

3000

3500

0 500 1000 1500 2000 2500 3000 3500 4000 4500

Production rate, STB/D

Flo

win

g b

ott

om

ho

le p

ressu

re, p

si

Inflow (Reservoir) Curve

Tubing Curve

System Graph

INFLOW PERFORMANCE

SEMI (PSEUDO) STEADY STATE INFLOW (using

average reservoir pressure) kh(Pav - Pwf)

qo = -----------------------------------

141.2 oBo.[ln(re/rw) - 3/4]

where: P = pressure (psi)

k = permeability (md)

h = height (ft)

re = drainage radius (ft)

rw = wellbore radius (ft)

O = fluid viscosity (cP)

Bo = formation volume factor (bbls/stb)

INFLOW PERFORMANCE

PRODUCTIVITY INDEX

The relationship between well inflow rate and pressure

drawdown can be expressed in the form of a Productivity

Index, denoted ‘PI’ or ‘J’, where:

q

q = J(Pws - Pwf) or J = ------------------

Pws - Pwf

kh(Pav - Pwf)

qo = -----------------------------------

141.2 oBo.[ln(re/rw) - 3/4]

WELL & RESERVOIR INFLOW PERFORMANCE ( Successful design depends upon prediction of flow rate)

VOGEL Dimensionless reference curve based on the following equation: Q/Qmax = 1 - 0.2(Pwf/Pws) - 0.8(Pwf/Pws)2

where: Q = the liquid production rate, stb/d Qmax = the maximum liquid rate for 100% drawdown Pwf = bottom hole flowing pressure, psi Pws = the reservoir pressure, psi

FLOW REGIMES

FACTORS EFFECTING VLP

VLP is a function of physical properties not inflow

• Tubing ID

• Wall roughness

• Inclination

• Liquid / gas density

• Liquid / gas viscosity

• Liquid / gas velocity

• Well depth / line lengths

• Surface pressure

• Water cut

• GOR

• Liquid surface tension

• Flowrate

PRESSURE LOSS IN WELLBORE

P/Ztotal = g/gccos + fv2/2gcd + v/gc[P/Z]

TOTAL

PRESSURE

DIFFERENCE

GRAVITY

TERM

ACCELERATION

TERM

FRICTION

TERM

P/Z

CORRELATIONS Babson (1934)

Gilbert (1939 / 1952)

Poettmann & Carpenter (1952)

Duns & Ros

Hagedorn & Brown

Orkiszewski

Fancher & Brown

Beggs &Brill

Duckler Flannigan

Gray

Mechanistic

Proprietary

Effect of Tubing Size on Outflow

Inflow

(IPR)

Outflow

Flowrate (stb/d)

Pre

ss

ure

at

No

de

2 3/8”

2 7/8” 4 1/2”

3 1/2”

Produced Fluids Issues

Gas Oil Water

Hydrates Paraffin/Gel

Corrosion

Emulsions

Scale

Asphaltene

Flowability

Solid

Erosion

Paraffins or Waxes “The Cholesterol of the Petroleum Industry”

Costs the industry billions of dollars annually

Wells Productivity

– Lower production – Downtime during wax remedial jobs – Expensive wax chemicals

Flowlines Management

– Extra insulation on flowlines – Dual lines to enable round trip pigging – Downtime during pigging – Cost of chemical program

• Saturated component of a crude oil – crystallizes

upon cooling

• Structure

• Field Definition A low melting point soft solid deposit that forms on cold walls of well

tubing, flowlines and oil transport pipelines

What are Paraffins or Waxes?

CH3(CH2)nCH3

n > 20 Petroleum Wax

0

0.02

0.04

0.06

0.08

0.10

10 20 30 40 50 600

0.02

0.04

0.06

0.08

0.10

10 20 30 40 50 60

Carbon Number (n+2)

Ma

ss

Dis

trib

uti

on

Crude Oil Wax Deposit

Lab and Field Observation Fluid Behavior

Paraffin Deposition in Flowlines

Heat loss to surrounding

Warm

Crude oil

Toil

@w

all

Wax Appearance Temperature

Cooled

Crude oil

Location from oil wellhead

Current Methods of Paraffin Control

Chemical Inhibition

Thermal Insulation

Hot Solvent Treatment

Mechanical Removal

Chemical Inhibitors for Paraffin Control

• Chemical performance is crude

specific

• Need a rigorous laboratory testing

program to qualify a chemical

• Screening of wax inhibitors using

cold fingers or flow loops

Wax inhibitors, hot solvent / dispersants

Coiled tubing access and wire line

Heat retention using Vacuum Insulated Tubulars (VIT)

Heating cable strap onto tubing string

Paraffin Control for Production Wells

Singh et al., SPE Drilling and Completions, 2007

Wellhead

750 ft750 ft750 ft

Warm

Reservoir

Fluid

1 2 3 4 5 6 7 8 9 10 11 12

Time (Months)

1 2 3 4 5 6 7 8 9 10 11 12

Time (Months)

Oil

Ra

te (

BO

PD

)

0

1000

2000

3000

4000

1

Time (Months) 2 3 4 5 6 7 8 9 10 11 12

Mechanical Methods for Wax Remediation

Pigging – Hard pigs, Scraper pigs, By-pass pigs, Multi-diameter

Coiled tubing – limited reach

SPE 77573

Improved pig design to lower the stuck pig risk

Sand Control What is meant by sand production?

Production of solids - type?

– Formation sand grains

– Formation fines

• Clay and Silica

• Compaction/detrital material

How much?

– 1-10 lbs/1000bbls or 1MMSCF

– In heavy oil, amounts could be very large

How much sand is tolerable?

– Depends on well location – offshore/onshore

– Fluid type - gas or oil

– Well type - subsea/platform/onshore

– Facilities for separation/handling/disposal

Causes of Sand Production

Sandstone strength linked to degree of cementation. Cementation increases over time →older sediments are more consolidated.

• Sand production more common in younger and shallower sediments.

Effects of production (pressure reduction and fluid movement) contribute to formation breakdown due to inertial and viscous forces.

• Pressure depletion increases grain to grain forces → potential to exceed compressive strength→ failure.

Causes of Sand Production

Inertial and viscous forces vary depending on the fluid e.g. gas or heavy oil → potential to exceed tensile strength→ failure.

There is a critical flow rate (drawdown) below which sand production can be minimized.

Relative permeability effects change the capillary forces within the grain structure (cohesion).

Impact on cementation - chemical attack reduces strength → increased risk of sand production.

Problems associated with sand

production Erosion - downhole and surface

Plugging ? – Sump and flowlines

– Perforations

– Pore space - fines!

Near wellbore compaction – Slumping of casing

– Subsidence

– Loss of productivity ( increased apparent skin)

Filling of separators – poor efficiency

Removal difficulties

Disposal of contaminated sand

Effects of Sand Production

Establishing Critical

Rate/Drawdown Well is “beaned up” progressively and sand production is

monitored

Concerns?

– Rock is tested to failure - does this weaken the rock - hysteresis?

– Is the failure affected by fluid type/saturation?

– Is QMSF an economic rate?

Prediction

– For a gas well, QMSF depends on (drawdown)0.5

– For an oil well, QMSF depends on : drawdown /strength / fluid saturation

Sand Management options

Production Rate Control Rate control is achieved by gradually beaning up a well and monitoring for

sand production. There are two principal values which characterise the technique: – – Maximum Sand Free Rate (MSFR) – – Maximum Allowable Sand Rate (MASR)

The onset of sand production in a well directly related to increasing production rate → implies there is critical rate below which sand production will not occur. This is the MSFR.

Establishing the MSFR involves well rate manipulation to the point where sand

is noted. This rate is kept constant until equilibrium is reached, at which point the rate is reduced back to a sand free rate.

The MASR is the rate at which sand production can be tolerated through the

production system without affecting its integrity. Economic decision as the rate which corresponds with the MASR may not be commercially viable (also applies to MSFR). Rate control has some advantages; – Generally lower CAPEX (unless major topsides modifications are required) and

flexibility to incorporate workovers if required. – Appropriate for situations where rates must be limited for water or gas ingress.

Sand exclusion options

• Screenless exclusion – Orientated perforating

– Sand consolidation

– Frac packs

• Physical exclusion - bridging

– Standalone Screens • Standard

• Premium

• Expandable

– Gravel packs

Oriented Perforation

Frac Packing

• Tend to use in heterogeneous, fine grained formations

• Optimal perforation design is

central to success of fracturing treatment.

• Perforations aligned with

maximum stress direction optimize impact of initiation and propagation pressures.

• Use of resin coated proppant

(RCP) may further help stabilize formation

Consolidation

• Treat formation in immediate vicinity of wellbore to bond sand grains.

– Formation must be treated through all perforations; Consolidated sand mass must remain permeable to well fluids; Consolidation should remain constant over time

• Two principal types of treatment;

– Epoxy resin (3 stage treatment) – isopropyl alcohol pre-flush, then resin is pumped followed by viscous oil to displace resin from the pore space). Limitations - only 20 ft at a time, temperature maximum of 100ｰC, max clay content 20%.

– Furan, phenolic resins & alkoxysilane– have higher temperature range than epoxy but consolidation may experience brittle failure. Difficult chemicals to handle safely.

Screens - Principles

• Sand control using installed screens is designed to exclude all but the finest formation particles from being produced into the wellbore.

• Effective design of screens requires acquisition of core samples for particle size analysis. Seeking to induce particle bridging and dynamic filtration.

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