160.0212.01 Introduction to well control.pptx

Introduction to WC

1. Hydrostatic Pressure Intro to well control

2. Hydrostatic pressure Hydro = fluid Static = at rest Hydrostatic pressure: The pressure exerted by a column of fluid at rest. The hydrostatic pressure is found by multiplying the weight of the fluid by the height of the fluid column.

3. DEPTH PRESSURE Gradient formation fluid = 0.465psi/ ft - 0.1051 Bar/m Hydrostatic pressure

4. DEPTH PRESSURE Gradient SW = 0.465psi/ ft - 0.1051 Bar/m The shape and the size of the hole does not matter to the bottom hole pressure. Only the true vertical height (TVD)of the fluid collum Hydrostatic pressure

5. DEPTH PRESSURE 0.1051 bar/m 500m 1000m 500m x 0.1051bar/m = 52.5 bar 1000m x 0.1051bar/m = 105 bar Hydrostatic pressure

6. DEPTH PRESSURE 0.465 psi/ft 1500´ 3000ft 1500ft x 0.465 psi/ft = 697.5psi 3000ft x 0.465 psi/ft = 1395 psi Hydrostatic pressure

7. P = MW x TVD x k Here we say: Pressure in PSI = mud weight in PPG x depth in FT To make that happened, we will need a factor to convert ppg and ft to psi The conversion factor “ k ” is 0.052 and have the unit PSI/FT Hydro- means a fluid Static- means at rest Hydrostatic in the wellbore is from the mud Hydrostatic pressure

8. Further: Mud weight in PPG x 0.052 = Pressure gradient [psi/ ft ] What is the theory behind all this: Hydrostatic Pressure is the pressure exerted by a column of fluid at rest , and is calculated by multiplying the gradient of the fluid by the True Vertical Depth at which the pressure is being measured : Hydrostatic pressure [psi] = Fluid gradient [psi/ ft ] x TVD [ ft ] Hydrostatic pressure

9. is the fluid pressure in the pore spaces of the formation. Formation Pressure PSI Normal Formation Pressure Gradient = 0.465 psi/ ft

10. is equal to the hydrostatic pressure of the water occupying the pore spaces from the surface to the subsurface formation. Native fluid is mainly dependent on its salinity and is often considered to be: 0.465 psi/ ft Normal Formation Pressure

11. PRESSURE DEPTH NORMAL PRESSURE 0.465 PSI/FT ABNORMAL PRESSURE SUBNORMAL PRESSURE

12. Formation Pressure Formation Pressure 0.465 psi/ft Depth Normal Pf Abnormal Pf Subnormal Pf

13. 1 2 3 4 5 6 7 8 9 10 11 0.4 0.5 0.6 0.7 0.8 0.9 1.0 PSI/FT 26” 18-5/8” 13-3/8” 9-5/8” PORE & FRACTURE Fracture Pressure Pressure at which the formation will start to break down.

14. The function of well control can be subdivided into 3 main categories : Primary Well Control : The use of the fluid to prevent the influx of formation fluid into the well bore MUD. So What’s the need to monitor the mud parameters including: Mud density Mud Flow Pit levels Secondary Well Control : The use of the BOP to control the well if Primary WC can not be maintained EQUIPMENT Tertiary Well Control: Relief well HELP ! Principles & Procedures

15. Principles of Well Control Balance Hydrostatic Pressure is equal to Formation Pressure

16. Over-Balance Hydrostatic Pressure is greater than Formation Pressure Principles of Well Control

17. Under-Balance Hydrostatic Pressure is less than Formation Pressure Principles of Well Control

18. Primary control PSI PSI FORMATION FLUID PRESSURE MUD HYDROSTATIC 5000 4800 MUD HYDROSTATIC IN WELLBORE Mud Hydrostatic pressure prevent formation fluids entering the well bore

19. It is an influx of formation fluid into the wellbore that causes the well to flow What Is A Kick?

20. An Uncontrolled exit of the formation fluids at the surface What Is A Blowout?

21. Secondary Control

22. Blowout Preventers (BOP) Annular Ram Side outlet valves Control Hoses Choke & Kill lines

23. Subsea Factor and Complications vs. Surface The difference between subsea and surface drilling operations can be described in the following aspects: Vessel Movement and weather (Emergency disconnect) BOP on sea bed, redundancy and configurations Water depth Riser above BOP (Gas expansion) Choke and kill line lengths and contents

24. Calculations Intro to well control

25. Areas Area of a square Area of a rectangle Area of a triangle

26. Area of a circle Area of a sector of a circle Areas

27. Area of a segment of a circle Annular area or cross sectional area of hollow cylinder Areas

28. Annular Areas Pressure Testing / Upward Pressure

29. Areas Pressure Testing 18-3/4” BOP shear ram to 15000 psi on the Stump. Do the math......

30. Volume, Capacity and Displacement Area of a circle or Volume of a cylinder or

31. Volume in ft 3 of a 1 ft high cylinder when the diameter D is given in inches (in) Volume in bbl of a 1 ft high right cylinder when the diameter D is given in inches (in) Internal Capacity

32. D d H Volume in bbl of a 1 ft high right cylinder when the diameters D and d is given in inches (in) Annular Capacity

33. 1 ft Metal Displacement Weight of metal @ 7.85 kg/l 65.44 lbs/gal 65.44 lbs/gal x 42 = 2748 lbs/bbl 2745 lbs/bbl Weight (lbs/ft) = Displacement bbl/ft x 2745 lbs/bbl Weight lbs / ft Displacement = --------------------- = bbl / ft 2745 lbs / bbl

34. Pump Displacement n = number of cylinders D = Inside diameter of the cylinder liner in inches l = length of stroke in ft n = number of cylinders D = Inside diameter of the cylinder liner in inches l = length of stroke in inches ŋ= dimensionless factor representing the volumetric efficiency

35. Barrier Concept Intro to well control

36. Norsok Standard D-010 - Terminology 3.1.38 Primary well barrier First well barrier that prevents flow from a potential source of inflow. 3.1.47 Secondary well barrier Second well barrier that prevents flow from a potential source of inflow 3.1.62 Well barrier Envelope of one or several well barrier elements preventing fluids from flowing unintentionally from the formation into the well bore, into another formation or to the external environment. 3.1.63 Well barrier element A physical element which in itself does not prevent flow but in combination with other WBE’s forms a well barrier 3.1.60 Ultimate well barrier stage Final stage of a well barrier element activation sequence which normally includes closing a shearing device. Well Barriers

37. Well Barriers A barrier has the intention to reduce or avoid the consequence of an unwanted situation or accident. This includes both technical ( ie : Bridge Plug which maybe the current Active barrier ) human and organizational barriers ( ie : Procedures or Passive barriers ) If we look at well barriers, it consists of one or several barrier elements that form a continuous and protective envelope around the wellbore. Its purpose is to prevent an uncontrolled and unintentionally gas or fluid flow into another formation or to surface [2] The well barrier ensures the overall safety on board a platform and it also prevents contamination of wellbore fluids into the environment. Should a barrier or a barrier element however fail, actions to replace and reinstate the failed barrier or barrier element should be number one priority, all other well related activities should temporarily be stopped until the barrier or barrier element is fixed and reinstated [4].

38. API Standard 65-2 Terminology 3.1.7 Barrier (barrier element) A component or practice that contributes to the total system reliability by preventing liquid or gas flow if properly installed. 3.1.34 Mechanical barrier A subset of physical barriers that features mechanical equipment, not set cement or a hydrostatic column. 3.1.45 Physical barrier element Physical barrier element can be classified as hydrostatic, mechanical or solidified chemical materials. (usually cement) Well Barriers

39. API Standard 65-2 Terminology 4 Barriers 4.2 Physical Barrier Element 4.3 Hydrostatic Barrier Element- when monitored or maintained 4.4 Annular Mechanical Barrier Element Generally tested to maximum differential pressure, taking flow direction into consideration . Plugs set as close as possible to source. (to allow density of fluid above to provide same pressure as below. Well Barriers

40. Drilling Activities Drilling shearable Norsok D-010 5.8.1 Well Barriers

41. Drilling Activities Non shearable DP Norsok D-010 5.8.2 Well Barriers

42. Inflow test Defined differential created by reducing pressure on the downstream side of a Well Barrier or Well Barrier Element (the differential has to higher than max exposure) The test is performed for a reason: ensure proper planning, including: How is it done in a safe manner? What is the success criteria? Maintain volume control whilst in displacement/bleed off mode especially the point of going underbalance must be known. What is the fail criteria. Volume / Pressure? How can we determine where a potential leak come from- surface or equipment being tested How do we recover in case of failure (leak or function)? If pressure or volume do not meet expectations, the well must be shut in as quickly as possible and situation evaluated as per plan. Fluids in the well will give hydrostatic pressure. With height and weight the Pressure hydrostatic can be calculated

43. High level Low level Well Control Risk Management

44. What can I do to be more effective at risk management? The following tips draw on common failings in risk management and can help your team perform better: Put real time and effort into risk assessment: identifying hazards, assessing risk level, and considering good control measures. Remember that paperwork alone doesn’t control the risk Make sure you and other crew are trained and competent at conducting risk assessment. Always remember the hierarchy of controls. Are there better control measures that should be raised with management? Encourage a positive attitude to risk management and risk assessment amongst your fellow crew. It is human nature to cut-corners. We often think ‘it won’t happen to me’ , but shortcuts in risk management lead to many incidents, including a great many fatalities. A little extra time spent on risk assessment can mean the difference between someone making it home to see their family, or not. Well Control Risk Management

45. Well Control Training Well Control training is required as a minimum for Essential crew on a regular basis every 2 years OGP are an important stakeholder and make Well Control training recommendations to improve standards and competencies within the industry which are currently being implemented into IWCF training syllabus. One of OGP recommendations is that both technical and non technical competencies (Human Factors) are included in future training requirements, in combination with team based training. Well Control Risk Management

46. API 59 Recommended Practice - DRILLS Pit Drill Simulated pit gain Trip Drill Installation of the FOSV at the shoe during a trip Strip Drill At an appropriate time. Close the annular, with DP in the hole, with the desired pressure trapped, each crew member is assigned a task. Enough pipe is stripped into the hole to establish workability and crew to be proficient in stripping operations

47. Drills Continued …. Choke Drill Similar to above, with BOP closed circulating down the string up through the choke, accurately monitoring flow rates to the trip tank, and to gain proficiency in choke operation. Especially important for subsea operations. Diverter Drill Should be performed by following a rig procedure for the correct operation of the diverter for offshore rigs without the BOP stack installed, and also for floating rigs with the Subsea BOP installed.

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