Production Engineering

Production Engineering

Prof. ir. Koen H. Bracquené q

Table off contents 1 The production system 1.

5. Artificial lift

1.1. Well flow capacity 1.2. System intake performance

5.1. Pumping 5.2. Gaslift

2. Completion 6. Rigless well intervention 2.1. Completion configurations 2.2. Completion equipment 3. Pay zone borehole connection 3.1. Completion fluids 3.2. Perforating 33 S 3.3. Sand d control t l 4. Well stimulation 4.1. Acidizing g 4.2. Hydraulic fracturing

6.1. Wireline 62 C 6.2. Coiled il d tubing t bi

Inflow Performance Response for oil wells productivity index

Open flow potential of gas wells laminar/Darcy

turbulent/non-Darcy

back pressure test

Open flow potential

Production process

for production to occur bottom hole pressure must be lower than formation pressure and more than the backpressure caused by the whole downstream circuit

Tubing performance choke to stabilise the pressure in the flow line: pressure downstream of choke is unaffected by upstream pressure if flow through choke is supersonic; generally when upstream pressure is at least twice downstream pressure

IPR

C Choke performance f ((1)) gas flow rate through a positive choke

C Choke performance f ((2))

oil flow rate through a positive choke

S System intake performance f any changes on the system will impact flowrate: well stimulation tubing diameter separator pressure …

maximum possible flowrate Qmax is intersection IPR and SIP

pressure losses in tubing and flowline (Cte x Q **2)

hydrostatic pressures in tubing and flowlines + separation pressure (PHtbg + PHfl + Psep)

C Completion configurations f (1) ( )

open hole completions

cased hole completions

C Completion configurations f (2) ( )

single zone completions

dual zone completions

C Completion configurations f (3) ( )

tubingless completions single g selective completion p

Horizontal completions 

Increase kh (low permeabilty, thin,…)



Increase drainage/recovery and recovery rate (fewer wells, lower draw down, reduce gas and/or water production,…

Surface and subsurface completion

Packers (1) ( ) Retrievable: run as an integral part of the tubing and can be released and recovered on the tubing / can be set by compression or tension, mechanically (manipulation at surface) or hydraulically (dropping a ball and pressuring-up tubing) / compression, tension and tensioncompression i type t

Packers (2) ( ) Permanent: tubing can be released from the packer and can be pulled leaving the packer as an integral part of the casing / can be set mechanically, hydraulically or electrically by wireline (explosive charge gives gas pressure) / to be destructively removed by milling / withstands any pressure differential hydraulic setting

packer picker milling tool

Production tubing

maximum erosion velocity ((a)) (b) (c) (d) (e) (f)

API integral i t l API non upset API external upset Elastomer VAM CS hydril

Tubing design (1) ( ) collapse, burst and axial loads similar to casing design based on worst case scenarios collapse: full evacuation, partial evacuation, tubing leak, annulus pressure test,… burst: producer well killing, injection pressure (injector wells), stimulation pressure,… axial loads: running, pulling (including overpull to release from packer or latch,…),… design factors: collapse: 1.10 b burst: t

1 10 1.10

axial:

1.30

Tubing design (2) ( ) length changes for freely moving tubing and tubing with packers allowing limited movement 1. freely moving tubing

Tubing design (3) ( )

Tubing design (4) ( ) 2. packers allowing limited movement

Tubing design (5) ( )

Circulating devices and landing nipples

S Subsurface f safety f valves subsurface controlled

surface controlled

control line

pressure differential

pressure operated

wire line retrievable

tubing retrievable

C Completion ffluids (1) minimal damage to the reservoir, (2) keep the well safe and kill the well when needed for intervention, (3) cleaning the well

Additives:

Perforating f (1) ( )

shaped h d charge h jet: 20 000 ft/s; 5 000 000 psi API RP 43 standard characteristics

positive pressure flow test

EH:0.25 EH:0 25’’- 0.50 0 50’’ TCP: 2’’- 18’’ reverse pressure flow test

Perforating f (2) ( ) Casing guns

Tubing guns

Perforating f (3) ( )

fire

Overbalanced Before completion Casing guns

Underbalanced After completion Tubing guns

release

Underbalanced After completion Casing guns

produce

S Sand control (1) ( )   

Washing out of reservoir and possibly cap rock Sand accumulation in bottom of the hole, reducing h or even plugging Equipment erosion, corrosion

screens

gravel packing

consolidation

S Sand control (2) ( ) high density gravel pack

Acidizing mainly used to restore near well bore permeability after plugging during drilling, completion or production Carbonates: 15 % HCl by weight concentrations are used HF undesirable in view of CaF2 precipitation 

Sandstones: 3 % HF + 12 % HCl by weight concentrations clays are dissolved into H2SiF6 and H3AlF6 

additives: corrosion inhibitors, wetting agents, demulsifiers, clay stabilizers, surfactants,…

basic reactions: 4 HF + SiO2 SiF4 + H2O + CO2 2 HCl + CaCO3 CaCl2 + H2O + CO2 2 HF + CaCO3 H2O + CaF2 + CO2

Hydraulic fracturing f

S Sucker rod pump (1) ( ) Polished rod

Q=SxNxA Q is flow rate S is stroke N is strokes per time unit A is area of the plunger efficiency factor to be involved

R pumps (a) fixed cylinder and moving plunger (b) moving cylinder and fixed plunger

T pump

150 bpd (10000 ft) – 1500 bpd (2500 ft)

S Sucker rod pump (2) ( )

tubing anchor gas anchor

S Sucker rod pump (3) ( ) asynchronous rate

tensile load on a tapered rod Fo = fluid load Wrf = weight of the rods in the fluid

S Sucker rod pump (4) ( )

Counterweight Effect tensile load on a tapered rod Fo = fluid load Wrf = weight of the rods in the fluid

S Sucker rod pump (5) ( )

PBH = PR - (Q/PI) PBH is bottom hole flowing pressure PR is reservoir pressure p PI is productivity index Q is required flow rate

pump to be submerged as: •PR declines with cumulative production/time •avoid gas entering the pump (PBH>PB)

S Submersed centrifugal f pump

centrifugal pump stage t

number of stages is the THD (Total Dynamic Head) divided by the delivered head per stage adjusted from water to the specific gravity of the fluid to be pumped

Hydraulic pump

turbine

centrifugal pump

jjet p pump p plunger pump

turbine pump

surface f facilities f iliti

Moyno pump

G lift Gas f (1) ( )

continuous gas lift PI > 0.45 bbl/d/psi 95 % of wells in gas lift

intermittent gas lift PI < 0.45 bbl/d/psi

self gas lift

surface facilities

G lift Gas f (2) ( )

G lift Gas f (3) ( )

casing operated valve

side pocket mandrel

start up with continuous lift

G lift Gas f (4) ( ) positioning tools

Wireline (1) ( )

Wireline (2) ( )

spang jar j

t b l jjar tubular

mechanical jar

restricted t i t d fl flow, tensioning line

restriction t i ti ends, d stem acceleration

i impact t

hydraulic jar

closing l i jjar

Wireline (3) ( ) running tool

pulling tool

Wireline (4) ( )

gage cutter hydraulic

mechanical bailers

scratcher

wireline grab

impression block

overshot

Coiled tubing Applications: clean out operations, acidising, plugback, sand consolidation (silicalock),…

Advantages: fast rig-up, high running speeds, live well applications, no kill fluid, no impairment,…

Disavantages: live wells, limited pulling capacity, it lilimited it d rotational t ti l capacity it