A Crown 4:1 pressure sensor debooster is used in a hydraulic system to sense pressure and transmit this pressure to a hydraulic pressure gauge. This sensor consists of a 4:1 debooster housing, 4:1 piston, debooster cap, check valve, hex stainless steel cross, and diaphragm separator (CD401)and 1502 union.
As the pressure is transmitted through the hydraulic hose on the outer side of the debooster, it is 4 times stronger than after it passes through the debooster. The deboosters housing is engineered to reduce the pressure at a ratio of 4:1 and works with a rubber diaphragm to achieve this reduction. As the hydraulic fluid enters the debooster, it fills the chamber and the pressure is lessened. For example, if the pressure is 16,000 PSI on the drilling side of the debooster, it will be 4,000 PSI on the gauge side of the system.
All Crown pressure sensors are engineered to withstand the harshest oilfield conditions. A debooster will protect the sensitive gauge internals from harsh drilling fluids. Because the Bourdon tube and linkage assembly are the most sensitive part of the gauge, they must be protected and a debooster does just that. The second advantage to using a debooster is that it reduces high pressure to a lower pressure, protecting workers. High pressure hoses are subject to intense pressures, especially in fracking and cementing situations. By reducing line pressure, workers are protected from a possible hose leak or blow out. Third, high pressure hoses are expensive, and a debooster can lessen the cost of operations because it requires lower pressure hoses to transmit pressure to the gauge. Fourth, hydraulic systems are easy to repair in the field, which ensures long, dependable use. Finally, deboosters, because they are hydraulic systems, do not require electricity to operate. When electrical components are unavailable or when an economical option is needed, a debooster is the best choice.
4:1 Deboosters are available in a variety of pressures and durable and dependable in the harshest conditions.
Torque, measured in foot/pounds, is a force that twists an object that causes rotational motion. When torque is applied to oilfield tubulars, that force needs to be measured in order to avoid twist offs. Using a tong torque gauge will assist the driller in determining the max torque needed to make up and break out the drill string.
Crown Oilfield Instrumentation offers a complete line of tong line pull and tong torque systems for use with manual and hydraulic oilfield tongs. Tong torque systems are used with manual or electric tongs when the handle length is known and is not changed. Unlike tong line pull systems, tong torque systems are not universal, meaning not interchangeable with a variety of tong handle lengths. These systems measure the foot pounds of force that are applied to a compression or tension load cell and transmit that information via a hydraulic hose to the gauge. These gauges, either available in box or panel mount, are located on the driller's console.
In order to select the right tong torque system, the following information is needed to be sure that you have the best system for your application. First, you'll need to know if you'll be using these gauges with a manual or electric system and if you'll be using a tension or compression load cell. Second, you'll need to know the max capacity that will be measured. Gauges, like car tachometers, work best at 3/4 scale or less. Think of the red zone on the tachometer that measures the working speed of your car's motor. Hydraulic gauges work best below three quarters of scale, just like your car's motor. So, if you know max torque then you can use a gauge within the 3/4 scale tolerance and be able to measure any extreme values above tolerance. Next, the handle length is needed to calibrate the gauge and select the proper load cell. The whole system is calibrated based on the max torque and the handle length of the tong in our factory so that the driller does not have to do so. All of these parts of the system, gauge, load cell, and hose, work together to show the driller what foot/pounds of torque are being applied to the oilfield tubulars that he his working with.
Tong Torque gauges are built to last and stand up to the harshest industry conditions. Because these gauges are fluid-filled, they resist fluctuations and vibrations that result in day to day rig operations. With a target pointer attached to the gauge glass, the driller can easily see at a glance when max torque is being achieved. These gauges, along with the complete system, are easy to repair in the field, offering a lifetime of dependable use in the field.
Our Mississippian Lime wells have been costly to drill sometimes taking up to 70 days. We have to make short trips and extra reamer runs to smooth the hole. Not many companies ream while drilling in the Miss Lime but I think it may save some some time and money. What are your thoughts? thanks
A first for Thailand: Buying property with a 20-year visa
In what is the first initiative of its kind in Thailand, one property developer has joined forces with Thailand Elite to offer a 20-year visa for purchases at its Pattaya condominium.
Purchasers at Kingdom Property’s Pattaya Southpoint development will be entitled to a 20-year visa, which amounts to five-year multiple-entry visa that is renewable every four years.
The visa will entitle its holders to benefits that include fast-track immigration clearance, assistance with driving licences, discounts and a bilingual helpline.
Nigel Cornick, Chief Executive Officer of Kingdom Property (pictured), said: “The long-stay solution will overcome many of the barriers that we see when selling our properties overseas. Generally unless you have a business visa, retirement visa or marriage visa, you are not permitted to stay for any length of time.
“This exciting partnership is akin to Malaysia’s My Second Home (MM2H) program and has massive potential.”
The visa will come as part of the purchase of a unit at Southpoint and the owner can sell the unit and the visa together, if he or she so wishes.
“The target demographic for this initiative is very wide,” added Cornick.
Website Link: http://www.kingdomproperty.com/20-year-visa/
Youtube Link: https://youtu.be/98-bCbLguj0
What’s Been Missing from the Macondo Explanations?
On April 20, 2010, the loss of control of the Macondo well led to the loss of Deepwater Horizon (DWH) and the lives of eleven contractors and crew members. The resulting oil spill would cause the greatest ecological damage in the Gulf of Mexico since the blowout of Pemex’s well Ixtoc-1 in 1979.
In a series of technical papers, Ron Sweatman and several industry colleagues, among them Juan García, formerly director of global drilling at Exxon, and Robert Mitchell, former Halliburton Technology Fellow, came to a new understanding of the root cause of the Macondo accident—that is, the original reason why formation fluids entered the wellbore several hours after the cementing operation.
This new understanding uncovered a technology gap in drilling and completion operations. Neither in 2010 nor at present, has there been a downhole tool or software program that could have alerted the mud crew that disaster was ahead. In 2015, with similar well conditions, both drilling and completion crews are as much at risk for the loss of well control as they were in 2010 in relation to the root cause of the Macondo accident.
Long before 2010, it was known as a general fact of fluid mechanics that all fluids to some extent are compressible and can shrink or expand; that is, changes in pressure or temperature will result in changes in density. It was known that a drilling fluid called synthetic-based mud (SBM) is highly compressible with a much higher coefficient of thermal expansion compared to water-based mud.
The oil industry had been aware that during drilling operations with SBM (which was used as the drilling fluid on the Macondo well) shrinkage could occur; but there was no way to differentiate actual shrinkage from the static loss of circulation, or “top-level fallback,” that occurs when fluids have leaked into the formation that surrounds a well. In either case, the correct response would be to insert mud into the wellbore. If the mud crew fails to make this response during drilling or cementing operations, the risk of a blowout is created, as shrinkage brings with it a loss of hydrostatic pressure. During cementing, a loss of density compromises the integrity of the cement during the curing phase of 14-21 hours.
In 2010, the science that explains the need for an open fluid column during the curing phase was only partially understood. Missing then was a precise understanding of the effect that changes in wellbore temperature have on volume, hydrostatic pressure and density. In API’s standards today, an explanation of the need to maintain an open fluid column during curing is only minimally presented; readers are left with the mistaken impression that hydrostatic pressure would be unaffected by isolating the wellbore from the riser.
On Macondo, the installation of the casing seal at the wellhead shortly after the placement of the cement created a closed system, which meant that the hydrostatic pressure would now respond to changing conditions in the wellbore. These changes would be undetectable by the crew.
The higher temperature of the rock formation affected the properties of the fluid: As the SBM in the casing cooled, a thermal-induced shrinkage led to a loss of density which, in turn, led to a loss of overbalance pressure in the trapped fluid column (from the wellhead to the hydrocarbon-bearing formations).
When, during the first two hours in which the cement was still a slurry, the equivalent density, or hydrostatic pressure, became less than the pore pressures in the rock formations, creating an underbalanced condition. Formation fluids, brine, oil and gas, penetrated the wet cement, creating flow channels into the weak zone below.
Over time, the flow channels grew larger, eventually building up sufficient pressure to penetrate the shoe track and enter the casing from below.
During this process, the DWH crew received no data or warning that the cement would not serve as a barrier. Today, there still is no commercial software product that would enable the thermal modeling of the behavior of drilling fluid in cases like this where geothermal gradients could affect fluid temperatures and pressures; nevertheless, there are measures that may be taken to cancel the effect of temperature. For example, the fluid’s temperature vs. the geothermal gradient may be made more stable by a complete top-to-bottom conditioning of the mud, a precaution not taken on the DWH. In some cases, mud temperatures may be adjusted on the rig to lessen the downhole effects. In addition, the setting of the casing seal should be delayed until after the cement sets hard enough to create a pressure barrier.
Looking back, neither drillers nor operators understood the importance of knowing about the changes that the formation can induce into the drilling fluid. They did not appreciate the danger that such changes could lead to an underbalancing of the well. It was this undetected change that occurred at the Macondo well that, combined with subsequent mechanical and human failures, led to the blowout and loss of the rig.
Looking forward, commercial software is needed to allow for routine thermal modeling in which the undetectable changes in the fluid properties are calculated as the fluid temperature equalizes with the surrounding formation temperature.
With the aid of such software, profiles over time may be plotted that show the effect for formation-induced changes on the properties of the drilling fluid. Such profiles would tell you if such changes induce the heating or cooling of the fluid. At Macondo, it was the cooling effect that led to the compromise of the integrity of the cement barrier.
In the meantime, the curricula of training schools, plus API standards, need to be updated to include instruction and guidance from this poorly understood risk to drilling and cementing operations.
Just like throwing an object in to a pool of water the things we do effect those around us. Who would be effected if we were injured? Family? Coworkers? Friends? Who else? No one that cares for us wants to see us hurt. Depending on the severity of the injury, the ability to interact with our loved ones with all of our senses could be compromised. What if we could not work anymore and were unable to provide income for our families? How would their lifestyles change? How would creditors and items we borrowed money to purchase be effected? Would the lenders just feel compassion for you because you were injured and let you continue without making payments or would they start repossessing those possessions that were financed? How long could you survive before you had to start selling other possessions just to make ends meet? How well could you survive on Government assistance such as food stamps and other programs?
Every action has a reaction or consequences. Those consequences are up to us to decide upon. It is your decision to work and be safe or take to chances and jeopardize your health or life. Nothing is more selfish than taking chances that could lead to that phone call to tell your loved ones that you are not coming home. How cruel is it to consider taking a short cut that takes away the father or mother of a child that counting on them for everything.
Nobody ever plans to get hurt. That is why it is so important to develop plans to ensure everyone we interact with returns home the same way they left. Their future and the quality of the future of everyone that relies on them depends on this fact.
If you want to change the safety culture of your people, don't just tell them what to do to be safer, teach them why being safe is important for them and how it effects the ones who love them. Just like a pebble thrown into a pond, the effects of that single action continue outward affecting untold numbers of people and events encompassing our lives.
Judge Barbier's 153-page report did not consider the chain of events set in motion by the placement of the casing seal assembly just 17 minutes after the placement of cement.
The cited "Field Test 2" in the 2013 SPE/IADC paper entitled "Modeling Reveals Hidden Conditions that can Impair Wellbore Stability and Integrity" is actually about the Macondo well (an important detail that is hidden from the reader).
Speaking with one of the authors this morning, he recalled,"We wrote the paper in a way so that the lawyers who were still worried about liability wouldn't understand it. Otherwise, they wouldn't have let us publish the data."
Since April, I have been collaborating with the author to get the data and a new narrative of the root cause of the accident into English. The short story is that the Macondo well began to migrate (flow) within minutes of the setting of the casing collar which took place 17 minutes after the end of the cement job.
For the past month or so I have been stuck in trying to explain to myself how the coefficient of expansion of a drilling fluid can affect wellbore stability. Any guidance would be appreciated.
The paper is copyrighted by SPE/IADC and is not available on the internet, making the story even more hidden from public view.