Continuing leadership from within - a myth?

We are always hearing how promoting from within to continue the helm from it's predecessor is better than seeking qualified and expertise from outside the organisation. It may be suggested that the long-term health of a company should be measured by whether or not it has produced and developed homegrown or in-house talent similar to developing or improving it's core business or competency. Some would argue that anybody  could buy or hire talent; only real leaders develop from it experience. It may hold truth or partially true but while it is important to build a “concrete foundation” for the successor, the truth is that, depending on the company and it's situation, it can be just as important and a need to bring in expertise from outside.

Managers or leaders may not be all “born” in the organisation; they all have to come from somewhere or develop their talent from within or from outside. And suggesting that companies are better off when every or even most executives “grow up” there is not only wholly untrue but may at times end up with wrong judgement. As with all things in business, there is no one-size-fits-all answer; it depends on the corporate needs of the company and what is it's long term strategic goal and it's core business. And more often than not, it’s not a question of either-or, but a question of balance and right choice.

Some big organisation that are famous for promoting from within - IBM, Caterpillar, and 3M, for example - however have all brought in outsiders when they needed to. After realizing that its “home-grown mentality” was hurting the company, company like Caterpillar began bringing in executive outsiders from Ford according to a Wall Street Journal story.  Also for 3M, it has hired outsiders for its last two CEOs. And we all know that bringing in former RJR Nabisco and American Express executive Lou Gerstner saved IBM.

In fact, most of America’s biggest and most respected companies - Microsoft, Apple, Google, Cisco, and Microsoft, among them - regularly hire executives from outside the company. Before joining Apple, COO and heir apparent Tim Cook was a vice president with Compaq and, before that, he spent 12 years at IBM. Ironic, considering Apple’s ancient feud with Big Blue. And Google CEO Eric Schmidt hails from Bell Labs, Zilog, Xerox, Sun, and Novell.

There could be no correlation between executives being promoted from within and the health or success of a company. As for the reason why that’s the case, it mostly comes down to this. There are indeed advantages for promoting from within, i.e. knowing the company and how it operates, growing up with the company culture, etc. But those same advantages can also be liabilities, since myopia and lack of perspective is probably the number one reason why executives and companies might have fallen into the red. The cloning effect of leadership from within may not bring new ideas or "out-of-the-box" concepts from external. Businessess have to generate new ideas to face up with competitions and myopic business acumen will kill the company in no time with short-sighted ideas within.

But what is a “leader” anyway? What does a “leader” do?
Who is better, a leader or manager ??

Some may consider the “leader” of the team as the person who formulate a working team and then got out in front of it to give direction and provide the vision for an action plan. The concept of a “leader” means that credit for what the team does goes to the leader but not the team. However the real fact is that you might see it in the lower level where leaders bloviate about leadership and try to inspire people, when in fact they’re usually just making everyone under them want to puke. What Drucker said — and most tend to agree — is that the business world doesn’t really need strong leader but better off with capable managers — people who can actually manage a team of staff especially working under tremendous work stress.  Being a great manager means being in service to the team. It means giving the team credit and making everyone else successful but himself.

Leadership and management may not go hand-in-hand or inter-related. While it could be true that there are different skill-sets, there are some intimately relationship. The truth is that good management skills make better leaders and the converse is also true. We could argue that great management requires excellent leadership skills. MBAs make better managers. You learn a lot getting an MBA - especially from a top notch school - if you aspire to be in senior management. There might be no credible evidence that it will make you or anyone else a better manager. That’s largely because management is more "art than science" as some management gurus would say. If you’re capable, you’ll become a manager but it takes a lot more than that to become a successful manager. Certain qualities and processes work better for certain people in certain organizations and industries, but that’s a far cry from a general blueprint for management success. Every so often you may about whether you should or shouldn’t get an MBA in engineering or technical field. There is no fix answer to such and it all depends on individual's aspiration and end of the day, there is zero loss should you decide to embark or spend S$50K-S$100K on an part-time or full time MBA degree. The knowledge you gain is worth every cent you had to spend.

So, as we go forward, let’s value the real managers ( so-call leader ), who actually do the hard work of making other people productive with high spirit.

Very likely scenario for most successful corporations is that they will continue to either selectively promote from within as well as taking the step to hire from outside the same time. They should do whatever they need to do to ensure the company has the necessary talent scouted and bring into the workplace new experience it required at that point in its evolution. There is simply no broad argument for choosing the leader or managers from within will be one sure success formula for any organisation. 

Drilling Contractor expectations & Equipment onboard

Common Specificatlona in Drilling Contract to an offshore drilling operator, usually a day rate for a jackup is around US$100K region and may be higher if the rig is working in north sea where the rig design is of higher specification :-

1) Depth in feet

2) Commencement date

3) Formations to be penetrated

4) Hole size

5) Casing sizes to designated depths

6) Drilling mud properties

7) Logging program

8) Cementing program

9) Type of testing

10) Well completion program

11) Size, weight and grade of drill collars

12) Hole deviation restrictions

A) More emphasis should be placed on the rate of hole angle change than on the maximum hole angle.

Types of Drilling Contracts

1) Turnkey Drilling Contract

A) It requires the Operator to pay a stipulated amount to the Drilling Contractor upon meeting contract specifications.

B) The Drilling Contractor:

-provides all of the labor.

-furnishes most of the material (contract specific).

-controls the entire drilling operation independent of any supervision by the Operator.

C) Provisions Common to Most Turnkey Contracts

-Location of well

-Commencement date

-Adequate location

-Conductor pipe, should be arranged for and set by the Drilling Contractor

-Contract depth, given as depth to which the Drilling Contractor should drill

-Hole sizes, includes the surface hole

-Price

1. includes these items usually fumished by the DrillingContractor

-Bits

-Water

-Fuel, ration, etc

-Surface pipe, and Intermediate pipe if required, clearly defined size, weight and grade

- API or non-API

- 3rd party testing equipment, logging unit, etc

-new, or if used, tested to (# ) psi

-cement (with additives)

-cement services

-maximum number of hours to wait before nippling-up (i.e. - set slips, cut off casing, etc.) operations are started

-Mud and chemicals

a. according to a mud program included in the contract

b. Specify who owns the mud at contract depth.

-Log type and Service Company

-All mobilization charges

a. move in

b. rigup

c. rigdown

d. move out

-Drilling the rat hole and mouse hole

-Cost of well control insurance

a. certificate

b) Straight hole specifications (e.g.)

-Unit to hole deviation per 500 feet, usually 3 degrees or less ?

- How frequently the DrillingContractor should survey the hole deviation

A. at least every 1000 feet ??

~ Clearly define when Daywork begins and ends (e.g.).

Daywork begins when:

A. a readable log is furnished to the Operator.

B. drilling reaches a certain depth.

C. drilling reaches a certain zone by cuttings, etc..

D. special operations such as drill stem testing and coring are done.

2. Daywork ends when:

A. blow-out preventers (BOPs) are nippled-down.

B. the tanks are cleaned.

C. the drill pipe is laid down.

A clearly defined deadline as to when payment is due :

1. This is normally handled through an escrow account at a bank that both the Operator and the drillingContractor agree to use.

A. a three-way agreement with the bank

2. The total Turnkey cost is held in an interest-bearing account.

A. The Operator receives the interest money.

3. All parties concerned sign a letter which spells out:

- the release of the contents of the account.

- other provisions of the terms of the agreement.

The Drilling Contractor is usually required to furnish evidence that all third-party bills are paid in full.

Below slides showing some of the machinery equipment inside the drilling rig  ( p/s : move your mouse to the photo, to see the title of each photo ) 

The rig crew has to carry out their maintenance of machineries,etc and there will be periodic or yearly classification renewal inspections required onboard, eg. testing of safety, fire fighting equipment, lifting appliances, padeyes,etc and renewal of classification certificate will be given.

Class of the rig will be suspended and the Certificate of Classification will become invalid in any of the following circumstances:

i) if recommendations issued by the classification surveyor are not carried out by their due dates and no extension has been granted,

ii) if Continuous Survey items which are due or overdue at the time of Annual Survey are not completed and no extension has been granted,

iii) if the other surveys required for maintenance of class, other than Annual, Intermediate or Special Surveys, are not carried out by the due date and no Rule allowed extension has been granted, or

iv) if any damage, failure, deterioration, or repair has not been completed as recommended.

Class is automatically suspended and the Certificate of Classification is invalid in any of the following circumstances:

i) if the Annual Survey is not completed by the date which is three (3) months after the due date,

ii) if the Intermediate Survey is not completed by the date which is three (3) months after the due date of the third Annual Survey of the five (5) year periodic survey cycle, or

iii) if the Special Survey is not completed by the due date, unless the vessel is under attendance for completion prior to resuming trading. Under exceptional circumstances, consideration may be given for an extension of the Special Survey, provided the vessel is attended and the attending Surveyor so recommends; such an extension shall not exceed three (3) months. More information may be referred to the rule book of any of the classification society or clarification with the society surveyor, if need to.

Emergency Response Saga in the Japan Nuclear Plant and BP Oil Spill

With the almost out-of-control catastrophic problem, miscalculated emergency response plan with ineffective rescue actions, these could describe the current situation at the Fukushima nuclear power plant but also par well and describes what had happened to the Deepwater Horizon rig that caused the major oil spill in the Gulf.

Seems like these events reminded all of us the crucial management involving such complex technology is not just wholly dependent on well-thought crisis response plans. Of course, such reactive plans will have to adapt to actual events and without a robust plan it won't work. It is lesson of vital importance to public or private organizations and the government in a host of technological activities that maybe potentially dangerous to all stakeholders. Not to forget our PM Lee just reminded singaporeans should a major act of terrorism involving nuclear, chemical, biological or cyber weapons occurs, either in private facilities or public spaces and that the nation should never let their guards down any minute.

Many of the problems relating to crisis response in Japan or with the Gulf spill still freshly in mind, shows how easy it is to talk the talk on these matters and how difficult to actually execute them correctly but with probability of high consequential results.

Although the Japanese nuclear event caused by the 9.0 richter quake is only a week old and information is fragmentary, it has a resemblance in a number of dimensions to the Gulf spill which occurred almost a year ago and has since been carefully analyzed (for example, the Report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, January 11, 2011):

Response Plan  -

Neither the Gulf spill nor the problems at the Japan nuclear plants were unthinkable. The possibility of a well blow-out was explicitly addressed by systems, processes and technology. Planning for the possibility of a severe earthquake and a subsequent tsunami were part of Japanese reliance on nuclear power. Yet, neither BP and the U.S. government nor Tokyo Electric Power Company (TEPCO) and the Japanese government had response plans which addressed the sequence of events that, though remote, were arguably foreseeable in environments where dangerous technology was located and which, in particular, addressed the additional issues outlined below.

Who is Responsibe and for what ??? 

The american government initially left the crisis management and response to BP. However the spill went uncontrollable and blown to a national issue, which later involved governmental direction and accountability.

In Japan, although the government has taken the lead on many aspects of the post-earthquake/tsunami crisis, there has been confusion about who is in charge at the nuclear plants. Where is the central government? Where is the nuclear regulator? As Michiyo Nakamoto pointed out in the Financial Times, the government inititially left many decisions to TEPCO (before forming a "joint" task force) , and then criticized the utility even though this is now a national emergency requiring the exercise of national authority and requiring military helicopters to assist in dumping huge amount of seawater to cool down the plant.

Inaccurate and misleading information ??? 

A host of factual questions were raised by Gulf Spill: How much oil was flowing? How could the flow be stopped? Where was the oil going (surface/sub-surface)? How could it be contained or removed? How could damage to environment/people/property be eliminated or mitigated? 

A similar set of problems bedevils Japan. There are critical questions about condition of the reactors; possible physical and chemical reactions in the reactor areas; actions being take to reduce those risks; radiation releases; health implications. Yet there has been a large number of voices from the government and industry which has left Japanese citizens and the world confused. Again, a single central authority needs to have seized control of the information flow and been as candid and explicit as possible about what is known, what isn't known, and how information gaps are being filled.

Thought and Decision-Making of what is best ???

There was substantial confusion for weeks after the Gulf spill about whether the company or different parts of government were making decisions. The decision-making processes on a host of crisis response issues (see preceding paragraph) were not set out clearly for the public — including comparision of options — and led to a perception of drift and lack of direction during a major national catastrophe.

A similar concern appears to apply in Japan, where opaqueness prevails about who is making decisions about what options, with what parties at the table, and with which other parties advising (from around the world). This, too, contributes to the growing sense that the public and private authorities do not have the situation in hand (and, in fact, may be losing control).

All Resources and implementation ???

In the Gulf, there were also serious issues about which private and public sector actors would implement which decisions — and about what resources were necessary. Indeed, just the lack of resource preparedness increased the severity of problems of containment and damage mitigation.

In Japan, it is very hard to tell at the moment who is responsible for carrying out which decisions at the nuclear plants as there has been shifting of employees around the plant (leaving, at the moment, 50 heroic technicians to deal with four reactors in stress and two more at risk at the Fukushima Daiichi plant) — and it is far from clear if regulatory experts (from inside or outside Japan) are on or near the site at all.

These are issues which every company with potentially catastrophic processes, products, or plants needs to answer with a special team of "worst case" analysts. Even in our KOM business of building drilling oil rigs with huge number of labour and many heavy machineries running on power generated from the diesel engines on board the rig, during testing of any marine or drilling system, there is need of prudent planning and close co-ordination among the experience engineers, commissioning staff, production labour, etc, before each of the system is ready for test and trial. There is no margin for error at all.

Practice makes perfect ??

Many would say that in emergency response and crisis management, without practice, without simulations, these response plans merely gather dust and are not effective when any of the least expected event occurs. In the military, war games can be a vital tool for learning how to respond to crisis situations. We need a "war game" mentality in the private sector to address the severe conceptual and operational problems in emergency response and managing crisis which the Gulf Spill and the Japan nuclear events so starkly have illustrated and shown to us. Many of lessons to be learnt by reading through the happenings and applicable even in our KOM kind of industry building oil drilling rigs. We are not free from trouble either and should not drop our guards, the seniors need to watch over the juniors to avoid human mistake which may affect the safety record.

Insights to ASME pressure vessel design

I started my career in 1980 as process vessel designer in CE-Natco, US company famous in process design of various types of onshore or offshore process vessels, such as 2 or 3 phases oil/gas/water separators, gas dehydration with glycol regeneration, flare system, oil dehydrators, steam boilers, etc....  Apparently now the company is owned by Cameron, ref web....Cameron_Natco   Petrobras, Brazil state-owned is one that  has many of Natco topsides ( glycol gas dehydration package ) installed in the semi-submersible platforms even to-date, like P51,52 and 56.

I have gained quite a bit of knowledge and work experience in the 80s' at CE Natco and understood ASME Section VIII Div 1 vessel calculations where it is somewhat much easier compared to Div 2 design which is seldom in the market needs unless very high internal pressure. It is normally advisable and better to use Div 2 when internal pressure exceed 1500psig in terms of thickness savings and other kind of advantages, eg. nozzle re-pad which will be difficult and this is done with using special forged nozzles with thick nozzle wall to compensate for the opening loss of metal. Also with the thick wall vessel, post weld heat treatment will be mandatory after the complete vessel is being fabricated to stress relief the heat affected zone and remove the stress locked. Lately I noticed there was introduction of Div 3 and this is "alien" to me as I have not seen this reference presently in my job on offshore rig engineering at current organization. In the old days, design calculations and drafting were all done manually but now with availability of design and drafting softwares, it is now much more easier for pressure vessel designers as well as drafters. Less thinking job, leaving it to the computer.

The ASME International Boiler and Pressure Vessel Code establishes rules of safety governing the design, fabrication, and inspection of boilers and pressure vessels, and nuclear power plant components during constructions. The objective of the rules is to provide a margin for deterioration in service. Advancements in design and material and the evidence of experience are constantly being added by Addenda. Originating in 1914, the ASME Boiler and Pressure Vessel Code is now adopted in part or in its entirety, by all 50 states and numerous municipalities and territories of the United States and all the provinces of Canada.

The Code is kept current by the Boiler and Pressure Committee, a volunteer group of more than 950 engineers. The Committee meets regularly to consider requests for interpretations, revision, and to develop new rules.

In the formulation of its rules and in the establishment of maximum design and operating pressures, the Committee considers technological advances including materials, construction, methods of fabrication, inspection, certification, and overpressure protection.

INTERPRETATIONS

ASME issues written replies to inquiries concerning interpretation of technical aspects of the Code. The Interpretations for each individual Section will be published separately and will be included with the update service to that Section; up to the publication of the 2013 Code. Interpretations of Section III, Divisions 1 and 2 will be included with the update service to Subsection NCA. Interpretations are not part of the Code or Addenda.

CODE CASE SUPPLEMENTS

Code Cases clarify the intent of existing requirements or provide, when the need is urgent, rules for materials or constructions not covered by existing Code rules. Cases will appear in the applicable Code Cases book: "(1)" Boilers and Pressure Vessels or "(2)" Nuclear Components. Supplements will be sent automatically four times per year to the purchasers of the Code Cases books up to the publication of the 2013 Code.

Vessels such as steam boilers, air compressors, storage tanks, accumulators and large pipes are subjected to internal fluid pressure which is uniformly distributed. All the above mentioned vessels are classified as cylinders or spheres.


THIN CYLINDER:
If the ratio of the thickness to the internal diameter i.e. t/d is less than about 1/20, the cylinder is assumed to be thin cylinder.

THICK CYLINDER:
If the ratio of thickness to the internal diameter i.e. t/d is greater than 1/20, the cylinder is assumed to be thick cylinder.

STRESSES IN CYLINDERS:
The following stresses are :
CIRCUMFERENTIAL OR HOOP STRESS:
The stress which acts tangent to the circumference and perpendicular to the axis of the cylinder is called circumferential or hoop stress. It is denoted by fh.

LONGITUDINAL STRESS:
The stress which acts normal to circumference and parallel to the axis of the cylinder is called longitudinal stress. It is denoted by fl.

RADIAL STRESS:
The stress which acts in a direction perpendicular to the internal surface is called radial stress. It is denoted by fr. Radial stress is very small as compared to fl and fh in case of thin cylinder and is therefore ignored.


I have compiled a set of slides and extracted some pictures from web and I thank those who has directly or indirectly contributed to the information in this slide presentation and if there is any violation of copyright, do notify me and I shall have no reservation in removing the content immediately from the presentation. There are some slides that have hyperlink to other external files which will not be readable below, I apologise for this inconvenience, however should you need more information, do drop me a note  :-

Pressure vessel slides


pressure vessel slides



Understanding Well Control

INTRODUCTION

The function of Well Control can be conveniently sub-divided into two main categories, namely Primary Well Control and Secondary Well Control. These categories are briefly described in the following paragraphs.

1.1.1 Primary Well Control (Hmud > Pf )

This is the maintenance of sufficient hydrostatic head of fluid in the wellbore (HMUD) to balance the pressure exerted by the fluids in the formation being drilled (PF).

However, it should be noted that balancing formation pressure is a theoretical minimum requirement; good drilling practice dictates that a sufficient excess of hydrostatic head over formation pressure, be maintained at all times to allow for contingencies. This excess head is generally referred to as ‘Trip Margin’ or ‘Overbalanced’.

1.1.2 Secondary Well Control (Hmud < Pf )

If for any reason the effective head in the wellbore should fall below formation pressure, an influx of formation fluid (kick) into the wellbore would occur. If this situation occurs the Blowout Preventers (BOPs) must be closed as quickly as possible to prevent or reduce the loss of mud from the well.

The purpose of Secondary Well Control is to rectify the situation by either:

a) allowing the invading fluid to vent harmlessly at the surface, or

b) closing the well in. i.e. providing a surface pressure to restore the balance between pressures inside and outside the wellbore.

This latter procedure prevents any further influx of formation fluid and allows any one of a variety of ‘Kick Removal’ methods to be applied thus restoring a sufficient hydrostatic head of fluid in the wellbore. This re-establishes the preferred situation of Primary Well Control.

BOTTOM HOLE PRESSURE

The term ‘bottom hole pressure’, as used here, means the sum total of all pressures being exerted on a well by our operations. Bottom hole pressure is the sum of the hydrostatic pressures exerted by the fluids in the well, plus any circulating friction loss (e.g. Annular Pressure Loss), plus any surface applied back pressures, where appropriate.

This is the total pressure exerted by us. It is usually intended to at least balance the formation fluid pressures in the exposed portion of the well.

FORMATION FLUID PRESSURE (PF)

The formation fluid pressure, or pore pressure, is the pressure exerted by the fluids within the formations being drilled. The sedimentary rocks, which are of primary importance in the search for, and development of oilfields, contain fluid due to their mode of formation.

ABNORMAL PRESSURES

Abnormal formation fluid pressures, or ‘sur-pressures’ as they are sometimes known, can arise for a number of reasons.

They can be categorised as:

a) Differential Fluid Pressure
b) Surcharged Shallow Formations
c) Sediment Compression
d) Salt Beds
e) Mineralisation.

The main causes of kicks are:

a) Failing to fill the hole properly when tripping
b) Swabbing in a kick while tripping out
c) Insufficient mud weight
d) Abnormal formation pressure
e) Lost circulation
f) Shallow gas sands
g) Excessive drilling rate in gas bearing sands


INDICATIONS THAT A KICK IS IN PROGRESS

1) During Drilling

There are several indications which show that a kick is in progress:
a) FLOW RATE INCREASE.
b) PIT VOLUME INCREASE.
c) PUMP PRESSURE DECREASE/PUMP STROKE INCREASE.

2) During Tripping

The indication of the presence of a kick is:

a) INCORRECT HOLE FILL VOLUME.

If this indication is not noticed at an early stage, it should become progressively more obvious.
In the extreme case the hole would eventually stay full, or flow, while pulling out. This may sound ridiculous, but it has occurred.

b) HOLE KEEPS FLOWING BETWEEN STANDS, WHILE RUNNING IN.

The presence of some or all of these indications require that a flow check be carried out to determine whether or not a kick is in progress.

When a kick occurs, the surface pressure required to contain it will depend mainly upon the size of the influx taken into the wellbore. A small kick closed in early means lower pressures being involved through the kill. Furthermore it is easier to deal with a kick which is noticed early and closed in quickly.

ANNULAR PREVENTERS

Annular Closing Times

• API RP53 state that surface annular preventers closing times should not exceed 30seconds for smaller than 18 3/4” and 45 seconds for 18 3/4” and larger.

• Subsea annular preveters should not exceed 60 seconds.

Shaffer Spherical BOP

Shaffer annular BOPs are rugged, compact and will seal on almost any shape or size- Kelly’s, drill pipes, tool joints, drill collars, casing or wireline. They also provide positive pressure control for stripping drill pipe into and out of the hole. The annular BOP is one of the first lines of defence in controlling a kicking well. When the BOP is actuated, hydraulic pressure operates, and in turns closes the spherical shaped preventer. The closure occurs in a smooth upward and inward motion, as opposed to horizontal motion.

Special features include:
• Rugged and reliable sealing element provides positive seal after hundreds of tests to full working pressure.
• Strong and simple construction-only five major parts.
• Simple hydraulic system-only two hydraulic connections are needed.
• Wear rings on movable parts prevent metal-to-metal contact. This feature prolongs preventer life.
• Suitable for H2S service.
• Servicing is easy- Element can be changed without getting mud and grit into the hydraulic system.


Diverters

A diverter is a safety system, which reroutes a well fluid flow away from the rig. Shallow gas is permitted to flow until depleted, or until the well is bridged over or killed by pumping in heavy mud. Ready during upper hole operations, a diverter is intended for use when there is a danger of penetrating a pressurised gas zone, while the casing shoe strength may not be sufficient to contain shut in pressures. Massive flows of gas and sand can quickly destroy a rig’s diverter system. Hydril incorporate integral valve functions and switchable target to minimise equipment and thereby decrease the risk of malfunction.


MUD GAS SEPARATOR (POOR BOY DEGASSER)

The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. As the mud and gas mixture enters the separator, the operating pressure is atmospheric plus pressure due to friction in the gas vent line. The vertical distance for the inlet to the static fluid level allows time for additional gas break-out and provides an allowance for the fluid to rise somewhat during the operation to overcome friction loss in the mud outlet lines. As shown in Figure 39, the gasfluid inlet should be located approximately at the midpoint of the vertical height. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention. The 30 in. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. The separator inlet should have at least the same ID as the largest line from the choke manifold which is usually 4 in. Some separators use tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture which causes faster gas break-out. The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. It is important that each plate be securely welded to the body of the separator with angle braces.

Well Control Basics

Guide to Drilling Eqpt Opns.pdf