upm 2016 state of the art for drilling fluid measurements ... · 01.03.2016 · title: microsoft...

24 – 25 February 2016 Houston, TX

State of the Art for Drilling Fluid Measurements and the Industry Needsby Jeff Robbie(standing in for Charles Orbell)

Agenda• Introduction to Drilling Fluids• Complexities of Drilling Fluids Measurement• Industry State of the Art• Managed Pressure Drilling• Improvements on and coming to Market• Ideal Drilling Fluid Measurement System• Technology in Development• Q&A

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Introduction to Drilling FluidsPurpose of Drilling Fluid

– Remove cuttings out of the well– Cool & lubricate drill bit– Maintain annular fluid column– Primary Well Control BarrierBasic Drilling Circulation System– Mud Pumps– Standpipe Manifold – Topdrive/Kelly – Drillstring (drillpipe, BHA, bit)– Annulus (space outside the drillstring)– Blow Out Preventer (BOP)– Flowline – Shakers (remove cuttings from fluid)– Pits (store clean fluid until used again)

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Annulus open to atmosphere

BOP

Drillstring carries drilling fluid downhole

Introduction to Drilling FluidsDrilling Fluid with Cuttings• Drilling fluid transports cuttings to surface• Drilling fluid properties determine lift efficiency• Without circulation, cuttings fall down to the bottom of the hole leading to pack off and loss of the Bottom Hole Assembly (BHA)

The Mud Circulation System

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BOP


Cuttings removed from System

Triplex Mud Pumps

StandpipeReturn Flow Line Paddle Flow Meter

Liquids to Active System

Degasser

Mud CleanerDischarge Solids

Clean Mud

Barite

Centrifuge

Discharge

1 2 3 4 5 6

Level IndicatorPits 1-6(Active System)

Mud Pump Stroke CountersTrip TankIncludesLevel Indicator

Introduction to Drilling Fluids

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Flow In • Clean mud is sampled from the pits

– Density – Viscosity– Rheology – Composition– No Cuttings– Possible sand & solids content• Intermittent Sampling– Drawn from active pit– This is the main drilling “tank”• Fluid in pit assumed to be homogenous


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Return Flow• Mud returns to rig with:

– Cuttings of assumed size, density and load– Assumed viscosity and mud density

• Mud immediately cleaned– Shale shakers

• Liquid/drilling solids separated by gravity through a screen– Solids Control

• Fine solids removed by use of centrifuge (if necessary)– Mud returns to active mud tanks– Mud is adjusted for properties by addition of chemicals and fillers


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Drilling Fluid Types• Liquids

– Oil Based Mud – Water Based Mud– Synthetic Based Mud

• Gas– Air, Nitrogen, Natural Gas

• Gas-Liquid Mixtures– Foam (mostly gas)– Aerated Fluids (mostly liquid)

Introduction to Drilling FluidsProperties of Drilling fluids

– Density: • Primary well control barrier for pressure containment

– Rheology: • Effectively balance cuttings lift vs. annular friction pressure

– Gel Strength:• Ability to form gel, suspend solids in annulus during connection

– Inhibition: • Mud to not react with subsurface fluids or formations

– Additives: • LCM, SALTEX, Surfactants, Hi-Vis Sweeps. Added to manage wellbore conditions. Properties must be monitored for changes

– Mud properties are intermittently checked at surface, – Mud properties not continuously checked at surface

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Complexities of Drilling Fluids Measurement

Complexities of Drilling Fluids MeasurementMud program updated as drilling progresses• Each hole section set new parameters:

– Density: bottom hole pressure balance– Viscosity: adjusted to optimize cuttings lift/friction– Fluid type: (oil, water, gas) updated based on expected formation rock & fluid characteristics

• Mud can exhibit all types of flow behavior depending on composition and pumping rates:– Laminar flow– Turbulent flow– Steady to unsteady flow– Newtonian and non-Newtonian behavior

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Complexities of Drilling Fluids MeasurementOther fluids utilized in drilling process• Cement – Setting and securing casing/liners• Acid – Dissolving mineral sediments, drilling evaporite rock• High viscosity pill – hole cleaning removing cuttings bed from well• Lost Circulation Material – additives to reduce drilling penetration into downhole formations• Salt(s) – salinity management with different types of salts• Surfactants –Drilling fluid maintenance

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Complexities of Drilling Fluids MeasurementVariable Flow Rate• Drilling is a stop - start process• Transient flow conditions mask critical indicators

– Most instrumentation requires minimum flow rate or fluid level to be in range:• Paddle flow meters, pump stroke counters, Coriolis • Time delay

– Drainage through mud processing equipment– Inconsistent true flow out (formation ballooning)

• Wellbore compressibility based on the total fluid compressibility which varies with depth (pressure)13

Complexities of Drilling Fluids Measurement• Gas cut during drilling

– Fluid density not representative of downhole– May affect performance of instrumentation – Flow through Mud/Gas Separator may be required

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• Cuttings loading dependent on penetration rate– Variable cuttings load: a function of penetration rate– Lag Time: time for cuttings to be lifted to surface– Slippage: cuttings lift not perfectly efficient– Circulation before a connection changes the return density profile

Variable Returning Density and Composition

Complexities of Drilling Fluids MeasurementUpset conditions common• Losses – drilling fluid lost downhole to formation

– Occurs when drilling fluid density is more than formation can support– Partial or complete loss of return flow while pumping in

• Kicks – gas injected into well from a formation– Occurs when formation pressure is more than drilling fluid density can contain– Gas migrates or is circulated to surface, upsetting instrumentation

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Complexities of Drilling Fluids MeasurementHigh pressure drilling fluid inflow • Few flow meters qualified for standpipe service

– Many flow meters perform poorly with low flow• Land rigs:

– 7,500 psi, from Zero to 1200 gpm– Land rigs now being used to drill HPHT wells

• Offshore rigs:– 10,000 psi, from Zero to 1800 gpm (15,000 psi BOP) – Market anticipating 20,000 psi BOP system soon

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Complexities of Drilling Fluids MeasurementLow pressure drilling fluid outflow• Return flow is to atmospheric pressure when drilling conventional wells• Hydrostatic head of pressure between the flowline and the shakers gumbo box may be very low • Gravity fed flow from top of well into mud system through large bore pipes

– Large bore pipes affect instrumentation accuracy• Essentially the same system used for over 80 years

– A round pipe used for construction convenience without any thought as to method of flow rate measurement !

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Complexities of Drilling Fluids Measurement3rd Party Sources• Some equipment is not part of rig package

– Brought in by service companies– May not be calibrated or input into Data Acquisition System

• Separately managed equipment, hydraulically connected to the well– Cementing System– Back Pressure or kill pump

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Complexities of Drilling Fluids MeasurementLine Sizing• Instrumentation sizing

– On return side, large bore pipe is common, 14”-18” – Difficult to accurately measure during connection– Circular cross section not conducive to low flow rate sensitivity

• Instrumentation range– Flow rates, mud type, density, etc. vary by hole section– Difficult to find one size fits all application e.g. mag flow meters only work for water based fluids

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The Past (Current) State of the ArtRepresents approximately • 98% of land rigs & • 95% of offshore rigs

The Past State of the ArtIntermittent Sampling of Density & Viscosity• Active Tank: Fluid ready to be pumped

– Assumed to be clean & homogenous throughout active pit system– Assumed no pumped sweeps (usually of much higher density and viscocity)

• Return Line: Fluid returning from hole– Represents a point in time, while return mud properties are variable with flow rate and time

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The Past State of the ArtIntermittent Sampling of Density & Viscosity• Manual Instruments Used for Sampling

– Marsh Funnel– Mud Balance– Rotary Rheometer

• Time & temperature dependence– Time delay from sample to measurement

22Fann.com

Holeproducts.com

Leutert.com

The Past State of the ArtInlet flow estimated by stroke counters on pumps • Triplex positive displacement pumps standard

– Stroke counters determine pump speed– Flow In = (pump speed) * (pump factor) * (efficiency)

• Common issues with inlet flow estimation– Loss of suction – not visible to control system– Inaccurate pump factor or efficiency– Tank or line up errors– Devices are fragile and prone to failure as they are added– Human Error in pump stroke calculation – liner changes– Pump not operating correctly or washing out

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The Past State of the ArtReturning Flow when Circulating• A paddle type flow meter indicating % of flow

– Affixed to return flow line– Usually no attempt made to calibrate to any flow model

• Return Flow Line not designed for measuring flow• Active tanks for volume control

– Volumetric account of system volume• subject to time delay as mud works through solids processing

– Pit Volume Totalizer sums volume in all active tanks– Deviations determine when well gains/losses fluid

• Fluid loss or gains in the system often due to leaks, human error, equipment failure• Coriolis Flow Manifold available as 3rd party service

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Source: http://petrowiki.org/

The System while Circulating

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BOP



Triplex Mud Pumps



Degasser


Clean Mud

Barite

Centrifuge

Discharge

1 2 3 4 5 6



The Past State of the ArtReturning Flow when not Circulating• Paddle meter (return flow line flow %)• Trip tank

– Tank with smaller volume than active system– Volume changes register quicker– Return flow line lined up to trip tank for flow check

• Transient Conditions: Connections– Stop/Start process results in flow rate issues– During connection

• Transients range from after flow to ballooning– After connection:

• Delay in return flow and flowrate spike due to breaking mud gel– Fluid loss or gains in the system often due to leaks, human error, equipment failure

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The System During Connection

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BOP



Triplex Mud Pumps



Degasser


Clean Mud

Barite

Centrifuge

Discharge

1 2 3 4 5 6



The Past State of the ArtPressure Indicators• Flow In - Standpipe pressure transducer• Flow Out pressure:

– Assume atmospheric when drilling conventionally

Pressure indicators of upsets result in increased/reduced return flow rate unless a closed system drilling approach is taken 28

The Past State of the ArtCurrent rigs manufactured with only ONE set of sensors for:• Active tank

– Circulating volume measurement • Trip tank

– More accurate volume measure when not circulating• Return flow

– Flow paddle or radar level, no supporting flow model• Inlet flow

– Mud Pump Stroke Counter29

The Past State of the ArtMud Logging Service added by Operators• A second set of sensors on a separate computer system• Anomalies between the rig and mud logging systems must be discussed between driller and mud-logger leading to questions:

– Which system is right?– Who is right?– Time delay in critical decision making process– If one sensor goes down, there is no back-up especially on return flow measurement

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Intermittent density in active tank

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The Past State of the Art

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The Past State of the ArtIntermittent density in active tank

Kick due to poor density control

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Kick during connection

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Managed Pressure Drilling

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Managed Pressure DrillingMPD: Adaptive Well Construction Process• Managed Pressure Drilling is a series of drilling technologies and processes intended to mitigate drilling hazards, improve drilling performance, and improve production rates. • MPD allows operators to increase economical reserves by enabling drilling of areas that were previously uneconomical to drill. • MPD Enables:

– Narrow margin drilling (i.e. pore/fracture gradient close together)– Control of down hole pressures through all drilling operations– Annular fluid gradient manipulation for drilling through depleted reservoirs or sensitive formations– Improved visibility into downhole events, improved response time and options for contingencies– Reduced NPT (worldwide surveys show over 40%), improved well economics

Managed Pressure Drilling• Conventional Drilling:

BHP (Bottom Hole Pressure) is determined by ECD (Effective Circulating Density)(Static mud weight + Frictional pressure loss effects)

Only adjustment: Pumps on, pumps off and pump speed

• Managed Pressure Drilling:BHP is determined by ECD and Applied Surface Back Pressure (Pressure is applied to a closed system with a choke)• BHP can be immediately lowered in the event of mud losses, or instantly increased if a kick is detected. • Kick detection and well control safety improved

The MPD Circulating System

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Annulus Sealed with Rotating Control Device

BOP

Fixed well volume, ability to apply back pressure


Triplex Mud Pumps

Standpipe


Degasser


Clean Mud

Barite

Centrifuge

Discharge

1 2 3 4 5 6

Gas Vent

Mud Gas SeparatorCoriolis Flow Meter

Pressure Control Manifold

Coriolis Flow Meter

Coriolis Flow Meter

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Managed Pressure DrillingMeasurement is much improved• The use of meters under pressure and continuous flow is enabled• Most MPD operations track delta flow in/out

– Common: Coriolis Flow Out, Pump Strokes Flow In– Deepwater Kick Detection: Coriolis Flow In/Out

• Mass Balance Calculations improved– Inputs: ROP, Specific Gravity, Cutting Velocity, Bottoms Up time, Rheological Properties– Used as kick indicator in addition to MPD BHP control

Improvements Coming to Market

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Return Flow and Density meter for open flow lines:• Optimised for low head height/low back pressure environments• Tolerant of high levels of solids and gas (< 2% error with 20+% gas by volume) • Modular• Low wear• No moving parts

Return Flow pressure-based measurements of flow and density as supplied by MezurX

Current Improvements Coming to Market

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For Inlet Flow and Density, and MPD Flow & Density:• Integral design optimised for reduced physical footprint• Higher back-pressure requirements• Tolerant of high levels of solids and gas• No moving parts


Current Improvements Coming to MarketMudMaster as supplied by ABLE• Gravity fed return flow line application

– Non-intrusive, non-contact, with no flow restrictions– Independent volume and density measurements to obtain mass flow with full or partially full pipe

• Multiple sensor array including:– Ultrasonic– Radiometric– Microwave– Pressure– Temperature

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Current Improvements Coming to MarketMudMaster• Flow Range

– 0–1320 gpm (simulated gravity flow through 12” pipe. Higher flow if coming from a pressurized wellbore)– Up to 2 SG, 16.7 ppg– Level Range: 0-100% full operation

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• Performance:– Density: +/- 2%– Volumetric Flow: +/- 2%– Mass Flow: +/- 3%– Temperature: +/- 2%

Current Improvements Coming to MarketABLE MudMaster• Applications

– OBM & WBM tested– Functions as standalone flow meter or with other kick detection systems

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• Applications– Return flow line upstream of shakers (MPD & conventional drilling)– Downstream of MPD manifold, upstream of MGS, shakers (MPD)– Second meter downstream of shakers provide cuttings density (MPD & conventional drilling)

Current Improvements Coming to MarketCoriolis Flow Metering• Coriolis meters tested for return flow

– MPD Operations: • Reliable flow indicator while circulating

– Transient flow issues:• Empty meter shows fault

• No Coriolis solution for high pressure injection– Materials traceability requirement (API)– Any injection application is upstream of mud pumps

• Line sizing is another consideration– Flow rate vs. Coriolis range

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Current Improvements Coming to MarketSonar Flow Metering as supplied by Expro:• Suitable for high pressure injection

– Flow measurement accurate with calibration– Measures turbulent structures in fluid

• Return flow line application– Peak Gas Rate

• Not as accurate without calibration– Limited return flow line application– Accuracy degrades with reduced turbulence (flow rate)

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Current Improvements Coming to MarketMagnetic Flow Metering• Concept

– Establish magnetic field in fluid flow through pipe• Known cross sectional area

– Meter monitors for changes in magnetic field• Changes in magnetic field correlated to fluid velocity

• Limitations– Fluid must be electrically conductive

• Not Suitable for OBM– System pressure

• Not suitable for standpipe applications

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Current Improvements Coming to MarketDeepwater Kick Detection System as supplied by MPO• Stand-alone product that monitors the well at all times• Requires minor modifications to the rig to enable enhanced kick detection while drilling conventionally;• Equipment is permanently installed and used for conventional drilling • Deepwater Kick Detection Kit consisting of:

– Classification approval by DNV;• Coriolis meters for pump suction side, including manifold;• Mud return rate Coriolis meter in the flow line;• Slip-joint displacement measurement and volume correction system;• Kick detection & loss detection software;• Density measurement in Riser.

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Current Improvements Coming to MarketDeepwater Kick Detection

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Current Improvements Coming to MarketDKD: Injection Coriolis Flow Manifold

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Current Improvements Coming to MarketDKD: Return Coriolis Flow Manifold

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• Downstream Coriolis installed between bulk head and shaker header box;• 14” flow diverter box placed around the header box.

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The Ideal System:

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A Production Process Perspective

Why do we need a production process perspective ?• Mud measurement and mud process equipment technology has not changed in 80 years.• Modern techniques for fluids and solids processing can be added to a rig to mitigate the inefficiencies and poor measurements that are gathered currently. • The way we have always done it is leading to blow-outs, rigs burning down and lost bottom hole drilling assemblies.

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The Ideal System

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The Ideal System• A kick is a high risk safety issue. Therefore the detection of a kick is a safety critical measurement. Each key measurement should have where possible:

– 3 measurements with 2 out of 3 voting– At least 2 different types of measurement– Continuous instead of intermittent measurement– Running on the same time and database i.e. going back to a high availability PLC system – Have SIL (safety Integrity Level) ratings where appropriate

A complete system, integrated with the rig• Automatic display of possible conclusions

– Direct rig crew how to react to positive indicators– Advise how to resolve faults

• Integration with Sub Sea Blow Out Preventor (SSBOP) measurements– Pressure, temperature at mud line – change in riser density– Measurements currently not used outside BOP controls

• Ultimately automated decision control to e.g. to close the SSBOP, taking out the human factor58

The Ideal System

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The Ideal SystemCurrent state of the art

MPO Deepwater Kick Detection

GOAL

Standpipe Metering Solution • Uncertainties caused by metering upstream of pumps

– Charge pumps cause flow through when pumps are off– Sweeps of varied densities, need to maintain mass balance– Assumed pump efficiency

• Standpipe conducts fluid from mud pumps to drillstring– All flow through standpipe is transported downhole– Volumetric & mass flow here is of highest operational value

• Challenge is the high pressure requirement

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The Ideal System

Cuttings Volume/Density Measurement• Returning flow contains cuttings

– Cuttings have a certain mass & quantity– Cuttings impact ECD (more cuttings, higher ECD)– Tracking cuttings reduces circulating time

• Cuttings measurement after shakers achievable– Measure return fluid density flow at return flow line– Measure fluid density flow from shakers to active pitEquation: Qreturn flow line – Qto active pit = Qcuttings

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The Ideal System

Technologies in Development

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Technologies in DevelopmentIn-riser measurement systems• Integrate BOP Pressure

– Riser length up to 12,000’ to mud line– Live riser density measurement

• Indicates changes to density/viscosity related to kick• Riser Temperature– Changes in riser temperature a kick indicator

• Pressure & Heave Compensation– Slip Joint Displacement Measurement

• Compensation for surging return due to heave• Adjustment of back pressure to eliminate back pressure fluctuations due to heave

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Technologies in DevelopmentDrill string sensors along the drill string with either:• Wired drillpipe (NOV system)• Repeat sensors along drillpipe• Allows Pressure While Drilling along borehole

• Allows BHP measurement• Leading indicator of influx• ECD measurement a realization of annular density

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Questions & Answers

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Copyright 2016, Letton Hall Group. This presentation was developed for the UPM Forum, 24 – 25 February 2016, Houston, Texas, U.S.A., and is subject to correction by the author(s). The contents of the presentation may not necessarily reflect the views of the UPM Forum sponsors or administrator. Reproduction, distribution, or storage of any part of this presentation for commercial purposes without the written consent of the Letton Hall Group is prohibited. Non-commercial reproduction or distribution may be permitted, provided conspicuous acknowledgment of the UPM Forum and the author(s) is made. For more information, see www.upmforum.com.

upm 2016 state of the art for drilling fluid measurements ... · 01.03.2016 · title: microsoft...

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