What is Primary Well Control?

Primary Well Control is hydrostatic pressure provided by drilling fluid more than formation pressure but less than fracture gradient while drilling. If hydrostatic pressure is less than reservoir pressure, reservoir fluid may influx into wellbore. This situation is called “Loss Primary Well Control”.

Not only is hydrostatic pressure more than formation pressure, but also hydrostatic pressure must not exceed fracture gradient. If mud in hole is too heavy, it will cause a broken wellbore, you will face with loss circulation problem (may be partially lost or total lost circulation). When fluid is losing into formation, mud level in well bore will be decreased that will result in reducing hydrostatic pressure. For the worst case scenario, you will lose the primary well control and wellbore influx or kick will enter into wellbore.

Typically, slightly overbalance of hydrostatic pressure over reservoir pressure is normally desired. You must keep in mind about the basic of maintaining primary well control that you must maintain hole with drilling fluid that will be heavy enough to overbalance formation pressure but not fracture formations.

References

Coleman, S. (2018). Well Control Quiz Online. [online] Well Control Quiz Online – Test Your Well Control Knowledge for Free. Available at: http://wellcontrolquiz.com/ [Accessed 2 Aug. 2018].

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

Accumulator Capacity – Usable Volume per Bottle Calculation for Subsea BOP

For subsea applications, hydrostatic pressure exerted by the hydraulic fluid must be accounted for calculation.

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In this case, we assume water depth at 1500 ft, therefore hydrostatic pressure exerted by hydraulic fluid (hydraulic fluid pressure gradient = 0.445 psi/ft) = 0.445×1500 = 668 psi. Besides of that, the concept for calculation is as same as surface accumulator. So please take a look about how to calculate usable volume per bottle as following steps.

Step 1 Adjust all pressures for the hydrostatic pressure of the hydraulic fluid:

Pre-charge pressure = 1000 psi + 668 psi = 1668 psi

Minimum system pressure = 1200 psi + 668 psi = 1868 psi

Operating pressure = 3000 psi + 668 psi = 3668 psi

Step 2 Determine hydraulic fluid required to increase pressure from pre-charge pressure to minimum system pressure:

Boyle’s Law for ideal gase: P1 V1 = P2 V2

1668 psi x 10 = 1868 x V2

16,680 ÷1,868 = V2

V2 = 8.93 gal

It means that N2 will be compressed from 10 gal to 8.93 gal in order to reach minimum operating pressure. Therefore, 1.07 gal (10.0 – 8.93 = 1.07 gal) of hydraulic fluid is used for compressing to minimum system pressure.

Step 3 Determine hydraulic required increasing pressure from pre-charge to operating pressure:

P1 V1 = P2 V2

1668 psi x 10 gal = 3668 psi x V2

16,680 ÷ 3668 = V2

V2 = 4.55 gal

It means that N2 will be compressed from 10 gal to 4.55 gal in order to reach operating pressure. Therefore, 5.45 gal (10.0 – 4.55 = 5.45 gal) of hydraulic fluid is used for compressing to operating pressure.

Step 4 Determine usable fluid volume per bottle:

Usable volume per bottle = Total hydraulic fluid/bottle – Dead hydraulic fluid/bottle

Usable volume per bottle = 5.45 – 1.07

Usable volume per bottle = 4.38 gallons

Reference book: Well Control Books

Drilling Formula Book Formulas and Calculations for Drilling, Production and Workover, Second Edition

Accumulator Capacity – Usable Volume per Bottle Calculation (Surface Stack)

Accumulator (Koomey) is a unit used to hydraulically operate Rams BOP, Annular BOP, HCR and some hydraulic equipment. There are several of high pressure cylinders that store gas (in bladders) and hydraulic fluid or water under pressure for hydraulic activated systems. The primary purpose of this unit is to supply hydraulic power to the BOP stack in order to close/open BOP stack for both normal operational and emergency situation. Stored hydraulic in the system can provide hydraulic power to close BOP’s in well control operation, therefore, kick volume will be minimize. Accumulators should have sufficient volume to close/open all preventers and accumulator pressure must be maintained all time.

koomey-unit

This post you will learn how to calculate usable volume per bottle by applying Boyle’s gas law:

Use following information as guideline for calculation:

Volume per bottle = 10 gal

Pre-charge pressure = 1000 psi

Operating pressure = 3000 psi

Minimum system pressure = 1200 psi

Pressure gradient of hydraulic fluid = 0.445 psi/ft

For surface application

Step 1 Determine hydraulic fluid required to increase pressure from pre-charge pressure to minimum:

Boyle’s Law for ideal gase: P1 V1 = P2 V2

P1 V1 = P2 V2

1000 psi x 10 gal = 1200 psi x V2

10,000 ÷ 1200 = V2

V2 = 8.3 gal

It means that N2 will be compressed from 10 gal to 8.3 gal in order to reach minimum operating pressure. Therefore, 1.7 gal (10.0 – 8.3 = 1.7 gal) of hydraulic fluid is used for compressing to minimum system pressure.

Step 2 Determine hydraulic required increasing pressure from pre-charge to operating pressure:

P1 V1 = P2 V2

1000 psi x 10 gals = 3000 psi x V2

10,000 ÷3000 = V2

V2= 3.3 gal

It means that N2 will be compressed from 10 gal to 3.3 gal. Therefore, 6.7 gal (10.0 – 3.3 = 6.7 gal) of hydraulic fluid is used for compressing to operating pressure.

Step 3 Determine usable fluid volume per bottle:

Usable volume per bottle = Hydraulic used to compress fluid to operating pressure – hydraulic volume used to compress fluid to minimum pressure

Usable volume per bottle = 6.7 – 1.7

Usable volume per bottle = 5.0 gallons

Reference book: Well Control Books
Drilling Formula Book Formulas and Calculations for Drilling, Production and Workover, Second Edition

West Atlas re-boarded – Photos Included

west-atlast-jack-up

Latest information about West Atlas and please find the media release from PTTEP t from the link below. You will see the photos of West Atlas after well control situation burnt the rig and the platform in Timor sea.

http://www.coogeeresources.com.au/uploads/MediaRelease96_23-11-09.pdf

From “Upstream Online” 23/11/09.

Crew Boards Crippled Montara Platform

A three-man team has boarded the Montara wellhead platform for the first time since a blowout at the Timor Sea installation on 21 August.

The crew, from Alert Well Control, are evaluating the damage to the Seadrill-owned jack-up West Atlas and the platform, PTTEP said.

The evaluation will also include a safety assessment as PTTEP considers how best to plug and fully secure the Montara H1 well.

PTTEP said the wellhead platform and blown-out H1 well remain stable after the leaking bore was successfully killed on 3 November.

Company director Jose Martins said a preliminary assessment of the rig shows extensive damage to equipment from a fire which erupted on the wellhead platform on 1 November.

He said the reboarding team were surveying the structural integrity of the West Atlas’ cantilever which buckled in the platform fire.

“PTTEP will ensure everything possible has been done to assess the risks before undertaking the plugging operation. The safety of personnel remains our first priority,” Martins added.

Understand about Friction Pressure Acting (FrP) in Wellbore

The friction pressure is pressure loss when fluid flowing through flowing paths and it acts in the opposite direction of fluid flow.

The following factors affect the friction pressure:

• Drilling string geometry both inside diameter and outside diameter

• Fluid Properties: Rheology and density

• Geometry of wellbore: hole length, wellbore area and flow area

• Wellbore condition such as packing off, bridging, etc

• Flow Rate

• Pipe movement and pipe rotation

Let’s illustrate friction pressure

  • Pump fluid with pressure upstream of 2,000 psi and discharge at atmosphere (0 psi)
  • Pressure gauge in the middle reads 1,000 psi
  • The diagram is shown in Figure 1.
  • Pressure acts in the opposite direction of flow.
Figure 1 - Simple diagram of fluid flow and friction pressure

Figure 1 – Simple diagram of fluid flow and friction pressure

  • Friction pressure between A and B is equal to P at A – P at B. Therefore, friction pressure between A and B is 1000 psi as shown in Figure 2.
Figure 2 -

Figure 2 – Friction pressure between A and B

  • Friction pressure between B and C is equal to P at B – P at C. Therefore, friction pressure between B and C is 1000 psi as shown in Figure 3.

Figure 3 – Friction pressure between B and C

  • Total pressure loss of this system (Friction Pressure) is 2000 psi (Figure 4).

Figure 4 – Total friction pressure between A and C

Friction in a wellbore

We will apply this concept to our wellbore.  This is a well with a normal forward circulation from drillstring and come out on surface from the annulus. These are some information.

  • Constant Fluid both sides
  • Hydrostatic Pressure = 2,500 psi
  • Friction P in Drillpipe = 1,500 psi
  • Friction P in Annulus = 500 psi

The well diagram is show in Figure 5.

Figure 5 – Wellbore Diagram

We can draw a simple diagram by applying U-tube concept as shown in Figure 6.

Figure 6 – Well Diagram applied U-Tube concept

Figure 7 shows the relationship in the drill pipe side.

DP – FrPdp + HPdp = BHP

Where;

DP = Drillpipe Pressure

FrPdp = Friction pressure at drillpipe side

HPdp = Hydrostatic pressure at drillpipe side

BHP = Bottom hole pressure

Figure 7 – Relationship on Drillpipe Side

Figure 8 shows the relationship in the casing side.

BHP =CP + FrPann +HPann

Where;

CP = Casing Pressure

FrPann = Friction pressure in annulus

HHPann = Hydrostatic pressure in annulus

BHP = Bottom hole pressure

** You will see that in the annulus friction pressure will act to the bottom hole since the flow moves upward direction so the sign is +.

Figure 8 – Relationship on Casing Side

Figure 9 demonstrates the whole relationship of the whole system.

Figure 9 – Relationship of the whole system

Let’s do some calculation to get more understanding about this topic based on this example.

Starting from the drillpipe side (Figure 10),

DP – FrPdp + HPdp = BHP

2,000 – 1,500 + 2,500 = BHP

BHP = 3,000 psi

Figure 10 – Calcification from the drill pipe side

Calculation from annulus side (Figure 11)

BHP =CP + FrPann +HPann

BHP =0 + 500 +2,500

BHP = 3,000 psi

Figure 11 – Calculation from the annulus side

Figure 11 demonstrates the whole system. As you can see that we can calculate the BHP from any side and we will get the same result as per U-Tube principle.

Figure 12 – Whole system calculation

With this example, we wish that would make you get more understanding about friction pressure in a wellbore.

Please leave any comments or questions below if you have any questions.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.