PTRT 1321 OilField Hydraulics Chapter 6 Pressure Basics

PTRT 1321 Oil-Field Hydraulics Chapter 6 Pressure Basics Oil and Gas Technology Program

Pressure Basics Force But: Stored energy is different and relies on compression Oil and Gas Technology Program

Fluid Pressure • Fluids exert pressure • Pressure in a column of fluid arises from density (weight of the column) • Pounds per gallon (ppg or lb/gal) or pounds per cubic foot (pcf or lb/ft 3) • Pressure Gradient - Pressure at depth is often described with psi/ft. This is the pressure generated for each foot of fluid depth. Oil and Gas Technology Program

Unit Conversion • Weight of the fluid column result in a certain psi/ft depending on the density of the fluid – requires a conversion factor • Constant = C PG = pressure gradient FW = fluid weight (ppg or pcf) C = constant (will be different number for ppg or pcf) C = 0. 052 when fluid weight is expressed in ppg C = 0. 00694 when fluid weight is expressed in pcf Oil and Gas Technology Program

Fluid Weight Constants • Volume has three dimensions • Picture a volume that is 1 cubic foot 12” x 12” • Also we know (by looking it up) that one cubic foot = 7. 48 gal • Therefore this gallon weighs 7. 48 lbs • The pressure at the base is then 7. 48/144 lbs/sq ft = 0. 052 psi/ft Oil and Gas Technology Program

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True Vertical depth • Gravity pulls down (only). This means the vertical depth is the only source of pressure exerted by the column of fluid • Directionally drilled holes might have measure depth that is much greater than the vertical depth • ONLY the True Vertical Depth (TVD) matters for calculations Oil and Gas Technology Program

Hydrostatic Pressure • Hydro = “water or fluid” • static = “not moving” HP = Hydrostatic Pressure (psi) PG = Pressure Gradient (psi/ft) TVD = true vertical depth (ft) • Example: PG = 0. 478 psi/ft and TVD = 6, 130 ft. Then HP = 0. 478 x 6130 = 2930 psi Oil and Gas Technology Program

A more complicated example Assume: TVD = 12, 764 ft filled with a fluid that weighs 15 ppg (density) What is the hydrostatic pressure at the bottom of the well? 1. Find Pressure Gradient. PG = 0. 052 x 15 ppg = 0. 78 psi/ft 2. Now find Hydrostatic Pressure. HP = PG x TVD = 0. 78 x 12, 764 = 9, 956 psi Hydrostatic pressure must be greater than or equal to the formation pressure to prevent well kick when not pumping Oil and Gas Technology Program

In Class Assignment Assume: TVD = 10, 000 ft filled with a fluid that weighs 10 ppg (density) Calculate the hydrostatic pressure at the bottom of the well? Place your name on the paper and turn in your work. Oil and Gas Technology Program

The Well as a U-tube • Work string is one leg of the U-tube • Casing annulus is the other leg • If both legs are open to atmosphere the pressure in both is the same and no fluid flows • Suppose that the work string has 10. 2 ppg fluid in it and the casing has 10 ppg fluid in it. • Pressure differential is created Oil and Gas Technology Program

10. 2 ppg Well simulation Oil and Gas Technology Program 10 ppg Pressure Differential

Gauge vs. Atmospheric pressure • Hydrostatic pressure at the bottom of a well also includes the atmospheric pressure • Check you gauges – psi means atmospheric pressure has been calibrated out – psig means atmospheric pressure is still there • Usually doesn’t matter since 14. 7 is small and there is fluid in both the tubing and casing and we’re dealing with pressure differences (see next section) Oil and Gas Technology Program

Example • Assume well is 10, 000 ft TVD and we use the previous fluids in the work string and casing HPworkstring = 10. 2 x 10, 000 x 0. 052 = 5, 304 psi HPcasing = 10 x 10, 000 x 0. 052 = 5, 200 psi Pressure Differential = 5, 304 -5, 200 = 104 psi Oil and Gas Technology Program

Formation Pressure • Fluid in formation reside in pores • Connected pores result in permeability • Formation pressure is the pressure of the fluids contained within the pores – Normal – pressure equals that calculated by the depth of the fluid column – varies by region (depends on salinity) Pressure gradient typically between 0. 433 – 0. 465 psi/ft – Subnormal – gradient less than fresh water can occur naturally in mountainous regions or from the production of formation fluids – Abnormal – gradient larger than 0. 465 psi/ft – sealed formations squeezed by shale or other overlying strata – Fluids are pressurized and can require fluid weights exceeding 20 ppg to control. Overburden pressure is equal to about 1 psi/ft Oil and Gas Technology Program

Fracture Pressure • Amount of pressure a formation can withstand before it fails (fractures) • Hydraulic pressure must exceed the formation pressure before fluid can enter the formation • Expressed as: – pressure (psi) – Fracture gradient (psi/ft) – Fluid-weight equivalent (ppg) • Often convenient to convert fracture gradient to equivalent fluid weight 0. 754 psi/ft ÷ 0. 052 = 14. 5 ppg Oil and Gas Technology Program

Fracture Gradient • Fracture Gradient typically increases with depth • Loosely compacted or shallow formations can have low fracture gradients • Exceeding fracture gradient can allow well pressure to vent into formation (lost circulation) • Can also undermine the surface strength under the rig • Fracture gradient knowledge is important wherever the fluid pressure is contacting a formation – for instance just below the surface casing Oil and Gas Technology Program

Formation Integrity Tests • Fracture pressure is determined using a leakoff test (LOT) or pressure integrity test (PIT) • Determines: – Adequate seal between casing and formation – Maximum pressure (fluid weight) that the well bore can withstand • Several factors to keep in mind – Fluid should be circulated – Check to ensure at required weight and homogeneous (uniform) – High-pressure/low volume pump Oil and Gas Technology Program

Leak-off Tests (LOT) • Pressure increased in 100 psi increments at ½ bbl volume steps • Stop pump and hold pressure for about 5 minutes • If pressure holds bump up another 100 psi and check again • As you approach the fracture pressure the pressure will drop off during the hold time • Alternative approach is to circulate fluid through a choke – close the choke so that you achieve 100 psi increments – monitor fluid volume until fluid is lost to formation (small volume tank) – Appears to yield a lower fracture pressure but friction losses do not show on the graph Oil and Gas Technology Program

A = no fluid loss B = start of fluid loss C = fracture pressure Oil and Gas Technology Program

Pressure-integrity Tests (PIT) • Performed when it’s unacceptable to actually fracture the formation • Use data from nearby wells in the same formation to estimate the maximum pressure the well can maintain without fluid loss (breakdown) • Pressure up the well to this level (or any other level below it) and check that it holds pressure Oil and Gas Technology Program

Maximum Fluid Weight and Surface Pressure • Knowing the formation-integrity test results provides an opportunity to calculate: – Maximum fluid weight – Maximum pressure • These are the values the formation can withstand without fracturing Oil and Gas Technology Program

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If Hole is Deepened after LOT or PIT Oil and Gas Technology Program

Example • • LOT performed at TVD 5, 821 ft Leak-off = 1, 250 psi w/ 9. 6 ppg fluid Now deepened to 11, 226 ft Fluid now in well is 10. 1 ppg ( ) ppg To find maximum pressure that can now be applied Oil and Gas Technology Program

Equivalent Fluid Weight • Regs or operator may require test to a certain equivalent fluid weight Oil and Gas Technology Program

Example • TVD is 5, 745 ft filled with 9. 1 ppg fluid • How much pressure should be applied to yield an equivalent fluid weight of 13. 4 ppg? Oil and Gas Technology Program

Equivalent Fluid Weight at Casing Shoe • Formation exposed to well bore directly below the casing shoe is most likely to fracture • Equivalent fluid weight that fractures the formation at the shoe can help ensure that fracturing does not occur • Assuming the shut-in pressure can be obtained from a casing gauge on the shutin well: Oil and Gas Technology Program

( ) Example: Casing Shoe at 3, 005 ft. Well is filled with 8. 8 ppg fluid Shut-in casing pressure = 375 psi ( Oil and Gas Technology Program )

Circulating Pressure Losses • Friction – resistance to movement – Density – Roughness of contact surface – Surface area – Surface properties • Force needed to overcome friction is called the frictional loss • For fluids typically measured in psi • Can amount to thousands of psi Oil and Gas Technology Program

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Circulating Pressure Losses • When fluid returns to surface will be at or near 0 psi • Pressure at the pump is almost entirely used to overcome frictional losses during circulation • In well control the most important pressure loss to consider is that which occurs in the annulus as this determines the BHP • When circulation stops BHP is reduced by the pumping pressure required to raise the fluid up through the annulus • If hydrostatic pressure alone is not sufficient to balance formation pressure then fluids will enter the well bore Oil and Gas Technology Program

Equivalent Circulating Density • Friction losses in the annulus increase the BHP • They equally increase the effective fluid weight • Both of these are akin to backpressure • Additional fluid weight caused by circulation is called ECD Oil and Gas Technology Program

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Determining ECD Oil and Gas Technology Program

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Swabbing and Surging • Swabbing – suction produced by tripping out – i. e. plunger on a syringe • Surging – pressure produced with the string is lowered too fast and the fluid can’t get out of the way • Both affected by: – Rate of movement – Clearances – Fluid properties • Friction • Viscosity • Suspended solids (inertia) Oil and Gas Technology Program

Trip Margins • Often a safety factor added to compensate for swabbing • Often equal to the circulating pressure to lift fluid up the annulus • Too large can cause lost circulation • Too small can allow the well to kick Oil and Gas Technology Program

Bottom Hole Pressure (BHP) • Hydrostatic pressure – accounts for most of the BHP • Annular pressure adds to this when circulating – usually less than 200 psi • Additional back pressure terms add to BHP as well – Rotating head – choke Oil and Gas Technology Program

Differential Pressure • Difference between BHP and formation pressure • Overbalanced: BHP > formation pressure • Underbalanced: BHP < formation pressure • Balanced: BHP = formation pressure • Never forget the importance of human pressure in well control – understanding is the key Oil and Gas Technology Program