Advanced Drilling And Well Technology

Deepwater Technology

Eng.Sherif Fathy

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Risks in deep water drilling

• Low seabed temperatures,• Highly unconsolidated formations,• Low fracture pressure,• Shallow water flow,• Shallow gas flow,• Narrow operational margin between pore pressure & fracture

pressure,• Depleted reservoirs,• Low temperature below 5⁰C lead to severe gel development, and

• Lower collapse pressure of the wellbore is higher than porepressure and/or the upper collapse pressure of the wellbore islower than fracture pressure.

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Drilling Fluids Systems In Deepwater

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Drilling Fluids Systems In Deepwater

• Aqueous systems:

– Water based drilling-fluid formulation

– Typical additives to the systems are polymers, bridgingsolids, lubricants, weighting agents, salts & defamers.

• Non-aqueous systems:

– Water-in-oil emulsions;

– Base oils:

• Internal olefins, normal paraffin, isoparaffin, ester etc

– Internal phase is a brine of low water activity to ensureshale stabilization

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Aqueous drilling fluid system formulation(1)

Additive Function

Concentration

WT%

Min Max

Sea water Continuous phase As needed

Soda ash Calcium remover 0.00 0.20

Xanthan gum Viscosifier 0.15 0.45

Polyacrylamide (PAC) Viscosifier 0.15 0.45

PAC polymer Fluid loss reducer 0.30 0.45

NaCl Shale inhibitor 5.00 31.00

Cationic polymer Clay-swelling inhibitor 1.50 2.00

Triazine Biocide 0.00 0.10

Caustic soda pH controller 0.00 0.45

Detergent Bit-balling preventer 0.02 0.10

Barite Weighting agent As needed

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Aqueous drilling fluid system formulation(2)

Additive Function

Concentration

WT%

Min Max

Water Continuous phase As needed

NaCl Shale inhibitor 2.8 31

Defoamer Foam Preventer 0.1 vol%

Xanthan gum Viscosifier 0.2 0.55

Modified Starch Fluid loss reducer 1.7 2.3

Magnesium oxide pH controller 0.25 0.45

Calcium carbonate Birding & weighting materials 10 14

Lubricant Lubricity agent 2-3 vol%

Triazine Biocide 0 0.15

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Non aqueous-drilling-fluid composition with a 70:30 oil/water ratio

Additive Function

Concentration

WT%

Min Max

Base oil Continuous phase 0.67 vol%

Primary emulsifier Emulsifier 2.50

Calcium Oxide Alkalinity 1.50

NaCl-saturated brine Internal phase 0.34

Secondary emulsifier Fluid loss reducer 0.40 1.70

Organic clay Viscosifier 1.00 1.20

Theology Viscosifier 0.50 0.60

Wetting agent Wettability As needed

Barite Weighting agent As needed

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Mitigation of Deepwater Drilling Risks

• Development efforts are focused on two different topics:

1) Dual gradient-drilling(DGD) systems, and

2) Noninvasive drilling fluids.

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Dual gradient-drilling(DGD) Systems

• Beneficial way of managing the narrow pressure window, an innovativedrilling process require new equipment & operational procedures.

• Has two effective fluid gradients:1. Between the surface & seafloor, and2. Within subsea well.

• Effective fluid density at the previous CSG is less than the effective fluiddensity at the current depth.

• Achieved by focusing on the development of systems based on twoapproaches:

1. Mechanical lifting: Consists of pumping system to lift the mud from the seafloor up to the surface.

2. The use of light weight fluids by diluting the mud returns at sea floor, through theinjection up ward to the surface of low –density materials, Mwt will be less thaneffective Mwt below seafloor: Injecting hollow spheres, and Injecting gas at the bottom of the marine riser to maintain the pressure in the subsea well

head equal to the hydrostatic pressure of the sea water at the same water depth.

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The use of light weight fluids

• Injecting hollow spheres:– As dilution material generates an incompressible light weight

fluid.– Will be reused after being extracted.

• Gas lifted riser DGD system:– Consists of injecting gas at BOP level to reduce marine-riser

annular density down to the seawater density.– Easy to implement than injecting hollow spheres.– The primary idea is to combine N2 injection with high pressure

concentric-casing riser.– The annular space between the outer & internal casing filled

with sea water to prevent collapse of the outer marine riser.– DGD involves the use of a closed pressurized circulating system.

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Noninvasive fluids

• Minimizing formation damage depend on a mininteraction between fluids and drilled rock.

• Require knowledge of filtration mechanisms ofsolids containing polymeric solutions in porousmedia.

• Designing factors of noninvasive fluids:– Evaluation of solids additives;

– Evaluation of polymers;

– Evaluation of noninvasive fluid formulation;

– Evaluation of solids shape, size & rock type.

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Noninvasive fluids

• Bridging materials act quite different during filtrationthrough a high-permeability unconsolidated porousmedium confirming the importance of shape effects onfiltration mechanisms.

• Particle & size distribution shape are the major factorsgoverning fluid invasion.

• Commercial noninvasive fluids based on physicochemicalmechanisms or surface interaction between additivesand permeable rock may be recommended for someapplication depending on rock type, down holeconditions & drilling scenario.

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Mud weight considerations

• Riser safety margin,• Kick tolerance, and• Tripping safety factors.

• Caused by thermodynamic interaction betweensynthic noninvasive fluids and the formation gas.

• PVT measurements of mixture of methane andorganic fluids currently applied in drilling fluidssystems for deepwater and ultra deepwater wells.

Gas solubility

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Density of the saturated fluid for methane in n-paraffin(NP) and in ester(E)

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Hydrates

• Ice looks like.

• Potential of forming hydrates increased with low seabedtemperature and high pressure especially in aqueousdrilling fluids.

• Drilling fluids formulated to inhibit or to delay of hydrateformation or preventing growth of hydrates once they are1st formed.

• Thermodynamics inhibitors used (Methanol, Ethanol,Glycol & Salts) to prevent hydrates

• Kinetic inhibitors used to delay hydrates.

• Antiagglomerants used to avoid growth of hydrates oncethey begin to form. 15GANOPE

Shallow water flows

• Is a result of:– Existence of an abnormal high pore pressure resulting from

undercompacted sands caused by rapid deposition(an underwaterlandslide known as turbidite depositional event),

– Hydraulic communication with deeper, higher –pressure formation,and

– Destabilization of gas hydrates during drilling, casing, and cementing.

• To avoid SWF:– Minimize water loss,– Minimize ECD,– Minimize surge pressures,– Use computational simulator to design the cementing job better by

adjusting the properties of the fluids to get better displacementefficiency,

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Offshore rigs statistics

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Worldwide overall Offshore Rig UtilizationRig utilization for the entire competitive rig fleet

Current Month ago6

Month ago1 year

ago

Rigs working 498 490 471 475

Total rigs 650 643 622 597

utilization 67.6% 76.2% 75.7% 79.6

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Offshore Rig Utilization by Region

Current Competitive Offshore Rig Utilization by Region

Africa - West 74.2% (46/62)

Asia - SouthEast 72.3% (68/94)

Europe - North Sea 91.1% (72/79)

Mediterranean 70.0% (14/20)

MidEast - Persian Gulf 68.4% (65/95)

N. America - Mexico 75.8% (25/33)

N. America - US GOM 70.1% (54/77)

S. America - Brazil 86.1% (62/72

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Offshore Rig Utilization by Rig Type

Current Competitive Offshore Rig Utilization by Rig Type

Drill Barge 80.0% (8/10)

Drillship 70.1% (47/67)

Jackup 74.5% (275/369)

Semisub 82.4% (145/176)

Tender 82.1% (23/28

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Offshore Rig Day Rates

Floating RigsRig Type Rigs Working Total Rig Fleet Average Day Rate

Drillship < 4000' WD 4 rigs 8 rigs $241,000

Drillship 4000'+ WD 45 rigs 62 rigs $458,000

Semisub < 1500' WD 11 rigs 18 rigs $249,000

Semisub 1500'+ WD 65 rigs 85 rigs $295,000

Semisub 4000'+ WD 78 rigs 104 rigs $425,000

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Jackup RigsRig Type Rigs Working Total Rig Fleet Average Day Rate

Jackup IC < 250' WD 32 rigs 53 rigs $73,000

Jackup IC 250' WD 35 rigs 64 rigs $79,000

Jackup IC 300' WD 88 rigs 127 rigs $91,000

Jackup IC 300'+ WD 118 rigs 154 rigs $141,000

Jackup IS < 250' WD 5 rigs 7 rigs --

Jackup IS 250' WD 7 rigs 10 rigs $137,000

Jackup IS 300' WD 2 rigs 5 rigs $60,000

Jackup IS 300'+ WD 1 rigs 3 rigs $55,000

Jackup MC < 200' WD 2 rigs 12 rigs $36,000

Jackup MC 200'+ WD 11 rigs 28 rigs $50,000

Jackup MS < 200' WD 2 rigs 2 rigs --

Jackup MS 200'+ WD 6 rigs 19 rigs $60,000

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Other offshore Rigs

Rig Type Rigs Working Total Rig Fleet Average Day Rate

Drill Barge < 150' WD 18 rigs 39 rigs --

Drill Barge 150'+ WD 6 rigs 9 rigs --

Inland Barge 20 rigs 74 rigs $43,000

Platform Rig 145 rigs 250 rigs $38,000

Submersible 0 rigs 5 rigs --

Tender 23 rigs 32 rigs $131,000

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Deepwater cementing

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Deepwater cementing

• The main difference in performing cementing jobs indeepwater wells compared with cementing jobs inonshore and shallow-water wells:– Very low temperature– Existence of different temperature gradients for the sea

and the formation,– Narrow operational window between pore pressure and

fracture gradient,– Possible occurrence of shallow water-or gas-flow,– Form destabilization of gas hydrates,– Fast liquid-to-solid transition, and– short thickening time.

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Temperature

• Bottom Hole Circulating Temperature(BHCT) foronshore and shallow wells can be determinedusing API spe 10(RP10B1997)

• Factors affecting temperature in deepwaterconditions re:– Ocean/sea-current velocities,– Sea temp,– Presence or absence of a riser, and– Heat of hydration of the cement slurry.

• If BHCT over estimated slurry reaction may beslowed much ”overlay retarded”

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Numerical heat transfer simulator

• Recommended to predict the temperature expected duringcirculation and temperature achieved because of the heat recoveryafter the circulation stopped,

• Numerical heat transfer recommended by ISO10426—3(2003), and• Should consider:

– Very low temperature– Existence of different temperature gradients for the sea and the

formation,– Narrow operational window between pore pressure and fracture

gradient,– Possible occurrence of shallow water-or gas-flow,– Well deviation survey,– More than 1 temperature gradient,– Circulation rate, time, and– Temp of injected fluid.

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Shallow water flows(SWF)• Will result in a poor cement isolation, which in turn can result in problems

such as buckling or shear of the casing.• Beside water other fluids can flow from shallow formation such as

mixtures of water & gas. Shallow gas causes fewer problems in deepwaterwells compared to conventional water depth and compared to shallowwater.

• The back pressure provided by the long sea water column reduce the gasexpansion so the wellbore erosion or failure caused by shallow gas is lesslikely.

• Influx of gas into the cement while is setting is obviously a problem.• The rapid set of the cement slurry is a very important characteristics to

avoid water flow during the gelation period, when the slurry begins todevelop gel strength and loss the ability to fully transmit hydrostaticpressure, causing an underbalanced condition that can lead to fluidinvasion.

• To ensure that hydrostatic pressure is always transmitted to theformation, two slurries can be used with different thickening times, thelead slurry having a longer thickening time than of the tail slurry.

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Hydrates & Cementing

•If gas hydrates are present beforethe cement job, it’s necessary toreduce the risk of destabilization ofgas hydrates by the use of cementslurries that generate low heat ofhydration.

•Figure shows the combination ofpressure, temperature, and gasdensity where the hydrates arestable.

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Cement systems

• In order to reduce the cement-slurry density, it’s necessary to useextenders as additives. Beside the density reduction, the use of extendersallows to reduce the amount of cement required to produce a givenvolume of slurry, the extenders can be classified as follows:

1. Water extenders are additives that allow the addition of water in excesswithout causing the setting of the cement slurry. Clays and water-viscosifying agents are water extenders.

2. Low-density materials are solids with density lower than that of the cement.3. Gaseous extenders are nitrogen or air used to prepare foamed cements,

reducing the density of the slurry

• Light weight of-cement systems include the following:1. Foamed cement.2. Extended cement with clays.3. Extended cement with diatomaceous earth.4. Microsphere cement.5. Optimized-particle-size distribution(OPSD) cement.

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Compressive strength vs. slurry density for different slurry compositions

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1.Foamed cement

• Consists of a mixture of cement slurry & nitrogen.• Used to avoid SWF problems• Very low densities[719 kg/m3(6 Ibm/gal)

minimum] with relatively high strength.• High ductility.• More difficult to prepare.• There is a requirement for more-precise control

to ensure that the base cement slurry andnitrogen are mixed together in the correctproportions and homogeneously

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2.Extended cement with clays:• The most common clay used as a water extender is bentonite,

mainly composed of sodium montmorillonite.3.Extended cement with diatomaceous Earth:• Composed mostly of very small amorphous silica shells of

organisms called diatoms.• Requires large quantity of water.4.Microsphere cement:• Hollow glass or ceramic microspheres can be added to the cement

to obtain cement-slurry density as low as 959 kg/m3 (8Ibm/gal).• The crush strength of different microspheres varies in a broad

range.• There are materials that can resist hydrostatic pressure greater than

414 MPa(60,000psi).• Microspheres can be added to the cement forming dry blend, and

because of the large density difference between the materials,gravity segregation can occur, with the light microspheres to the topof the blend. This can cause nonhomoginity in the cement column.

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5.Optimized-particle-size distribution(OPSD) cement:

• Used first by construction industry.• Part of the cement replaced by aggregates(sand &

gravels) and by other materials, such as fly ash,blastfurance slag or micro silica increasing thecompressive strength of the set concrete.

• This technology uses materials with different particle-size distribution in order to achieve a high packingdensity.

• The water amount used in these system is reducedcompared to conventional slurries.

• Higher content of solids responsible for the lowpermeability and high compressive strength presentedby this system.

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Physical properties of the cement systems

• Low density to avoid fracturing the formationthat presents a low fracture gradients,

• Fast liquid-to-solid transition and long-termsealing to avoid fluid or gas migration,

• Good control of fluid loss, and

• Zero free water and no sedimentation.

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Deepwater hydraulics

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• Understanding of phenomena governing bottom holepressure is necessary for high-cost ultra deep wateroperations.

• Presence of solids in the annulus pays a major roe inbottom hoe pressure prediction by two mechanisms:1. Solids travelling in the annulus transmit hydrostatic

pressure, which impact bottom hole pressure directly.This effect increases with water depth due to low annular

velocity through the riser.

Predicting impact of solids loading by considering an averagedensity of the fluid cutting mixtures.

– ρm = ρf(1 - cs)+ρscs

– cs :solids concentration(vol%), and

– ρf ,ρs:fluid & cutting density respectively.

Deepwater hydraulics

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Impact of cuttings concentration(Cs) at several water depth

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• In highly inclined sections may not transmit hydrostatic pressurebut will restrict flow area, and also will accumulate near-annulusrestrictions, resulting in pressure peaks.

2. Solids forming a cuttings bed

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1. Rate of penetration(ROP),

2. Well depth,

3. Pipe rotation,

4. Flow rate, and

5. Rheoogy.

Parameters affect solids concentration

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• In high angel sections the tendency towardcuttings-bed formation increases, while atlower angels, cuttings loading increase.

• Increase in ROP will result at ancrease of ECDin deepwater wells.

• ECD shoud be kept inside operational window.

1.Rate of penetration(ROP)

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Effect of ROP on cuttings concentration

In a deviated well In the riser

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• As the MD increase affects he frictional termsand so the ECD increases.

• This factor is irrelevant for clean large-diameter hoes.

• This factor is negligible for small diameterholes(0.241-m , 0.216-m and smaller)

2.Well depth

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Impact of the well length on fracture gradient

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• High pipe rotation enhance solidsresuspension which immediately affects ECD.

3.Pipe rotation

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• Increase flow rate will enhance the holecleaning and so will reduce solidsconcentration

• Friction losses are directly proportional toflow rate.

• ECD may increase or decrease depending onthe importance of both aspects.

4.Flow rate

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Impact of the flow rate regarding hoe cleaning & pressure drop effects

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