well problems and solutions,well problem ,solutions

8/10/2019 Well Problems and Solutions,well problem ,solutions

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WELL PROBLEMS AND SOLUTIONS

pg. 60 YENNAI HYDROCARBONS AND SERVICES PVT. LTD.

Well Produced Problems

Objectives

Understand the Well produced problems

Know how to remedy these problems.

Know what kind of problems that can occur within a separator.

Know how to remedy these problems.

Emulsions

Emulsions are stable mixtures of two immiscible liquids. Emulsions arestabilized by an emulsifying agent which is a film of surface active agents that

reduces the interfacial tension between the oil and water. Given sufficient time,

most emulsions will dissipate naturally.

However, to reduce the retention time needed and break the emulsion, the film

of emulsifiers is normally altered by heat, chemicals, mechanical devices or a

combination of the three.

The two main emulsion types are:

(1) water-in-oil (invert) emulsion(2) oil-in-water (direct) Emulsion

DemulsifiersThe demulsifiers or emulsion breaker chemicals are surface active and must

specifically target the particular emulsion being produced. The desired chemical

will penetrate the fluid, disrupt the emulsifying film, breaking the emulsion and

allowing the liquids to disperse. The demulsifiers can be injected downhole, inthe manifold or pipelines and by batch in storage tanks

Foaming Crude OilIf the pressure is reduced on certain types of crude oil, tiny spheres (bubbles) of

gas are encases in a thin film of oil when the gas comes out of solution. This

results in foam, or froth. Foaming greatly reduces the capacity of oil and gas

separators since a much longer retention time (up to 20 minutes) is required to

adequately separate and stabilize a given quantity of oil


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The main factors that assist in "breaking" foaming oil are:

1. Settling or retention time

2. Agitation

3. Heat

4. Chemicals (ex. Foam breakers or solvents w/silicone additives)

5. Vortex inlets

Paraffin DepositionParaffin deposition in oil and gas separators reduces their efficiency and may

render them inoperable by partially filling the vessel and/or blocking the mist

extractor and fluid passages. Paraffin can be effectively removed from

separators by steaming or by use of solvents.Paraffin buildup downhole can cause serious reduction in production to the

point of complete blockage. Some of the possible solutions employed, may

include:

Wireline scrapping

Hot oil treatments/circulation

Bacteria injection (certain types feed on paraffin)

Liquid Load up in Gas WellsThe occurrence of liquid loading up in the flowing tubing or annular string is

usually associated with wells of low to moderate gas productivity and high

water or oil to gas production ratios.

Initial indications of liquid in the hole may be an unusually low shut-in

wellhead pressures and/or a large difference between tubing head and casing

head pressures if there is no packer in the hole.

Hydrating ConditionsThe formation of hydrocarbon ice crystals or hydrates will occur at any point in

a gas or liquid hydrocarbon flow system, where the temperature reaches the

hydrate point for the pressure condition and the nature of the fluid in the system.

As a general rule, the hydrating temperature rises with higher pressures, and

starting with methane, also rises with the higher carbon components.

Since the throttling of a stream causes a drop in temperature by expansion, someof the common hydrating points on a surface flow system are:


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Chokes

Valves

Orifices

Sharp bends or restrictions in piping

Sand, MudSand production is more likely to occur with high productivity wells. The sand

may originate from the formation rock and be "sloughed off" into the wellbore,

or it may be sand recovered following a frac stimulation job. The risk of sand

production increases with higher drawdowns. Underbalanced perforating is

believed to produce perforations which are cleaner and less prone to sand

production because of reduced differential pressures at the perforations. Otherservices that may be employed, depending on the wells parameters, include:

Gravel packs / sand screens

Sand consolidation treatments

Sand production can be monitored at surface by:

BS&W samples at the choke manifold.

Erosion probes at choke manifold

Sand detectors measure the acoustical noise created by sand impinging

eitheron a probe in the flow stream or on the internal wall of the flow pipe.

H2SHydrogen sulfide, H2S, often called "sour gas," packs a double barreled punch.

H2S is a poisonous gas. There is the indirect threat to human safety caused by

H2S attack on metals, especially steel, used in pressure control equipment. H2S

is a colourless, flammable gas having an offensive odour and sweet taste. The

smell at low concentrations is similar to that of rotten eggs.

SymptomsExposure results in irritation, principally smarting of the eyes, a persistent

cough,

Tightening or burning of the chest, and skin irritation. There is no known

antidote for H2S.


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General Well Trends

CLEAN-UP PHASE

Wellhead pressure

Wellhead pressure will drop from the shut-in pressure as the well is opened

to flow.

Wellhead pressure will increase ass the fluid cushion and extraneous fluids

are replaced by lighter reservoir fluids

Wellhead pressure will slowly decrease with depletion of the reservoir

Wellhead Temperature

Well head temperature will increase with the flow of hot reservoir fluids

Wellhead temperature will stabilize with well flow stabilization

Annulus Pressure

Anuluspressure maybe altered for the operation of annulus pressure (apr)tools.

Annuluspressure will increase with the flow of hot reservoir fluids

Annuluspressure will stabilize with well flow stabilization


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BS&W Extraneous fluids will decrease and eventually dissipate

Water cut will stabilize

Salinity

Salinity will stabilize near formation water

PH After acidizing, waterpH will Steadily move toward 7.

H2S H2Slevels win increase then somewhat stabilize

Co2 Co2 levels will stabilize

Downstream of Choke Pressure

Pressure downstream of the choke will dependent upon wellhead pressure,

choke Size, fluid flow rates and test systems

Critical now conditions should exist


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Downstream of Choke Temperature will be less than well head temperature

due to expansion at the choke causing a cooling effect

Tank Volume

Extraneous liquid return will be initially high. Rates will be whp/choke

dependent

Flare/Burner

Quality ofburn will initially indicate the return of extraneous fluids.

Quality and intensity of fire will improve with the production of higher

percentages of reservoir fluids

Oil burner pressure will be dependent upon flow rate and nozzle(s)

arrangement; stabilizes with well flow.

Problem Solving Abnormal Trends

Clean-Up phase

Symptoms Cause ActionWell head Presure

Increasing Choke plugging Adjust choke

Choke Hydrates Use Heater

Chemical Injection

Increase Rate

Low Productivity Well

Continuing Clean-up

Nothing-Normal

Unloading of liquid in

in surges

Increase or Decrease

Choke Setting

Decreasing WellLoading Up Normally increase

Choke Size

Choke Cutting Inspect


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Decreasing Tubing hydration Reduce Rate

Chemical Injection

ShutIn

Annulus Pressure

Increasing Test String Leak Bleed Off

Possible Shut-In

Decreasing Test Siring Leak

Packer Leak

Abort IfNecessary

BS&W

Increasing Water ConingSand Production

Reduce Rate


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Increasing Choke Cutting

Downstream Restriction

Check Flow System

Decreasing Choke Plugging Adjust choke

Hydrate Formation Determine Hydrate

Point.

Adjust Choke, Use

Heater,

Chemical Injection

Downstream of Choke Temperature

Decreasing Larger Pressure Drop Stage chokes, Remain In

Critical Flow, Use

Heater

Choke Plugging Adjust choke


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Oil Burner Pressure

Increasing Nozzle Plugging Clear Nozzle

Decreasing Nozzle Cutting

Rate Declining

ReplaceNozzle

Stable Well Flow

Wellhead Pressure & Temperature will have stabi1ized at the end of clean-

up Annulus Pressure With stabilization of well flow; it will have stabilized

BS&W

Basic sediment should be insignificant

Water cut should be relatively constant

Salinity Should be relatively constant

Downstream of choke pressure


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With stable well now and critical flow at choke, downstream pressure will be

dependent upon Separator

Downstream of choke temperature

Will increase with decrease of pressure drop across the choke, will decrease

with increase ofpressure drop

Heater Temperature

If necessary, will be Stable provided stability of well flow and thermostatic

control

Separator Pressure

Willbe stable after final settingof controls

Separator Temperature.

Will be relatively constant provided heater temperature and/or well flow are

stable

Gas Measurement

Pressure Upstream of Orifice Effectively equal to separator pressure

Pressure downstream of orifice (Static) Slightly less than separatorpressure;

with stable flow. will increase with higher separator back pressure And/or

larger orifice plate size.

Differential Pressure

With stable flowdeviation of pressure upstreamand downstream of orifice is

dependent upon separator pressure & and orifice size; variance win increase

with decrease of separator pressure and/or small orifice.

Downstream Gas Temperature

Will be less than separator temperature due to expansion

Gas Specific Gravity

With stable well and separator conditions will be relatively constant: may be

seen to vary inversely with separator pressure


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H2S - Will be increasing constant

Co2- Willbe relatively constant

Oil Measurements

Oil Flow rates - With stable now will be relatively constant

Oil Temperature-Willbe close to separator temperature.

Oil API Gravity- With stable ratewill be relatively constant

BS&W- Water cut should be negligible

Shrinkage - Maybe seen to vary directly with changes in separatorpressure

Water Measurements

Water Flow rates With stable flow willbe relatively constant

GOR Saturated Oil Reservoir Will initially increase then stabilize

Other Reservoirs With stable flow should be relatively constant

Separator GOR - Will be affected by separator conditions; increases with

decreasing separatorpressure increases with increasing temperature.

Problem Solving Abnormal Trends

Stable Well Flow

Symptoms Cause Action

Well head Pressure

Increasing Choke plugging Adjust choke

Choke Hydrates Use Heater

Chemical Injection

Increase Rate

Low Productivity Well

Continuing Clean-up

Nothing-Normal

Unloading of liquid inin surges

Increase or DecreaseChoke Setting


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Decreasing WellLoading Up Normally increase

Choke Size

Choke Cutting Inspect


Decreasing Tubing hydration Reduce Rate

Chemical Injection

ShutIn

Annulus Pressure

Increasing Test String Leak Bleed OffPossible Shut-In

Decreasing Test Siring Leak

Packer Leak

Abort IfNecessary


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BS&W

Increasing Water Coning

Sand Production

Reduce Rate


Increasing Choke Cutting

Downstream Restriction

Check Flow System

Decreasing Choke Plugging Adjust choke

Hydrate Formation Determine Hydrate

Point.

Adjust Choke, Use

Heater,

Chemical Injection


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Downstream of Choke Temperature

Decreasing Larger Pressure Drop Stage chokes, Remain In

Critical Flow, Use

Heater

Choke Plugging Adjust choke

Separator Static Pressure

Increasing Back Pressure Problem Examine Controller/

Valve

Action

Downstream Restriction Check flow System

Decreasing Back Pressure Problem Examine Controller/

Valve

Action

Wrong Valve open Check Relief, Drain,

Liquid valves for exit

point


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Upstream Restriction Check flow System

Erratic Back Pressure Problem Examine controller/valve

Action: If cycling,

increase

P.B: If hunting, Decrease

Below Bubblepoint Reduce Rate: Put more

Back pressure on well

Separator Differential Pressure

Increasing Choke Cutting Verify WHP Drop

Replace Choke

Liquid or Leak In

Barton Downstream Line

Drain or Inspect

With Soapy Water

Temperature Increase Ambient or Heater

Decreasing Choke Plugging Verify WHP Drop

Adjust Choke

Liquid or Leak In

Barton Downstream Line

Drain or Inspect

With Soapy Water

Temperature Decrease Ambient or Heater

Separator Oil Meter Rates

Increasing Passing Gas Raise level, prove meter


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pg 75 YENNAI HYDROCARBONS AND SERVICES PVT LTD

at tank

Decreasing Damaged Meter Use Secondary Meter

repair/replace parts

Erratic Wrong Sensitivity Adjust Proportional band

setting

BS&W

Increasing Water level height Lower water level

Separator Water meter rates

Increasing Passing gas Raise level, prove meter

at tank

Decreasing Damaged Meter Use secondary tank

repair/Replace parts

Tank ReadingsErratic Foamy Oils, Emulsions Allow More Retention

Time. Use two

Compartment vessel

Liquid Densities Drain off Heavier liquid

to improve u-tube in

sight glass

Oil Burner Pressure

Increasing Nozzle Plugging Clear Nozzle

Decreasing Nozzle Cutting

Rate Declining

ReplaceNozzle

Flare visual

Abnormal Burn Separator Liquid Lower liquid Level,

checkSeparatorValving

for Exit Point

well problems and solutions,well problem ,solutions

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