Faulty cement jobs in the G.o.M.

     Faulty cement jobs in the G.o.M., and drilling histories     re-examined.

 July 5/2010

    I managed to dig up some information on the sealing of wells in the G.o.M. with various grades of cement, and the resulting problems that occur , .. why, ...and who's ultimately responsible for the final decisions concerning what kind of cement to use. I found some MMS/Coast Guard/D.O.E. documents that reveal some things...


                           The following is from a joint CBS/AP story.May 24, 2010 
  
   (CBS/ AP)  The tricky process of sealing an offshore oil well with cement - suspected as a major contributor to the Gulf of Mexico oil spill disaster - has failed dozens of times in the past, according to an Associated Press investigation.

  Yet federal regulators give drillers a free hand in this crucial safety step - another example of lax regulation regarding events leading up to the April 20 explosion on the Deepwater Horizon oil rig.

  Federal regulators don't regulate what type of cement is used, leaving it up to oil and gas companies. The drillers are urged to simply follow guidelines of the American Petroleum Institute, an industry trade group.
   An AP review of federal accident and incident reports on offshore wells shows that the cementing process has been implicated at least 34 times since 1978. Many of the reports, available from the U.S. Minerals Management Service that regulates offshore wells, identify the cause simply as "poor cement job."
   In a November 2005 accident where the Deepwater Horizon was positioned above another well in the Gulf, faulty cement work allowed wall-supporting steel casing to come apart. Almost 15,000 gallons (56,800 liters) of drilling fluid spilled into the Gulf.

   Just a week later in a nearby well at another platform, cement improperly seeped through drilling fluid. As a result of an additive meant to quicken setting time, the cement then failed to block a gas influx into the well.

   When the crew finally replaced heavy drilling fluid with lighter seawater, as they also did last month before the blowout at Deepwater Horizon, the well flowed out of control and much of the crew had to be evacuated.

   Cementing was identified by federal investigators as a glaring cause of an August 2007 blowout, also off Louisiana. They said, "The cement quality is very poor, showing what looks like large areas of no cement."

   Reports by MMS, a branch of the Interior Department, also provide evidence of the role bad cement work has played in accidents. One study named cementing as a factor in 18 of 39 well blowouts at Gulf rigs from 1992 to 2006. Another attributed five of nine out-of-control wells in the year 2000 to cementing problems.

   Cementing in the oil rig business is a sensitive, involved process. Well cement constitutes an essential barrier that is difficult to install and control, said Gene Beck, a petroleum engineer at Texas A&M University at College Station, Texas.
   Deepwater wells pose special challenges: severe pressures and temperatures, as well as the need for specialized equipment and lots of cement. The wellhead of the Deepwater Horizon operation sat on the ocean floor, nearly a mile (1.6 kilometers) from the surface. The drill hole itself went another 13,000 feet (3,960 meters) into rock.

   All cement begins as a slurry with cement flakes and water. Contractors then add ingredients to make the cement set at the right time and to keep out gas and oil.

   There are three major U.S. cementing companies: Halliburton, Schlumberger and BJ Services. Cementing is typically performed by such rig contractors as part of a broad range of drilling services that they supply.

   Halliburton, which had the Deepwater Horizon job, mixes in nitrogen to make its slurry more elastic. The nitrogen also helps create a lightweight cement that resembles a gray foamy mousse and bonds better to the casing.

   But the recipe also depends on the job, because cement must respond to varying pressures and temperatures. Cement contractors work closely with oil and gas companies on the formulas for individual wells. The oil and gas companies have the final say on what is used.
                             
                                                              ***
 .....that means that according to the current law, British Petroleum is ultimately responsible. It does not matter that Halliburton was an " independent contractor "
                                                              ***

   But the recipe also depends on the job, because cement must respond to varying pressures and temperatures. Cement contractors work closely with oil and gas companies on the formulas for individual wells. The oil and gas companies have the final say on what is used.

   Once the consistency of the mix is decided on, it is pumped deep into the well, where it first sinks to the bottom and then oozes upward to fill the narrow spaces between the steel casing pipe and rock walls. When the cement sets, the casing and cement are supposed to form an impenetrable wall to keep gas or oil from pushing into the hole anywhere but the bottom, where its flow up the pipe can be controlled.

   But if gas bubbles invade the setting cement, they can form a channel for pressurized gas and oil to surge uncontrollably up the well, usually around the casing. The cement must be strong enough to withstand up to 5,000 pounds (2,270 kilograms) of pressure per square inch (6.45 square centimeters), to keep the well walls from collapsing.

   "Cement is cheap, and it fixes a lot of problems, but it's not a good place to cut corners," Beck said. Many oil and gas companies will scrimp, though, if they don't think they need all the ingredients in the cement, he said. Cement is often squeezed in later to try to fill gaps, but Beck said the success rate of this remedial work is low.

   And if cement was part of the cause of the Deepwater Horizon catastrophe, it also could be part of the remedy. Two relief wells are being drilled to intersect the leaking well and plug it with cement.

   Halliburton was completing the final cement work on the exploratory well beneath Deepwater Horizon in the wee hours of April 20. It added an initial cement plug to the well to act as a cap until a later production phase.

   Workers started running a series of tests to check if the cement and casing could stand up to sufficient pressure. The first tests of outward, positive pressure showed no problems.

   In the first sign of trouble, though, the well then failed a negative pressure test, where internal fluid pressure is reduced, according to congressional testimony from a BP PLC executive. It showed different pressures in two areas, indicating an unseen leak somewhere in the well.

    Despite the test, managers eventually decided to replace drilling fluid with seawater and set a final cement plug so the well could be mothballed pending a decision to possibly begin production drilling.

   And while it is not yet clear what sections of the casing or cement may have failed - or why - it is known that the blowout ignited and exploded before the last plug was set.

   In the aftermath of the blowout, questions have been raised about the safety of nitrogen-laced cement foam. But several cementing experts told the AP it is a sound technique. Halliburton says it has used such a mix on scores of wells and told a congressional committee that the cementing on the Deepwater Horizon job was successful.

   Halliburton did not respond to AP requests for comment.

    In the wake of the accident, some experts support mandatory uniform cement standards for underwater wells. "When you change the composition, it should meet a certain standard. Such standards exist for the building construction industry," said Surendra Shah, Northwestern University engineering professor and director of the Center for Advanced Cement-Based Materials at Evanston, Illinois.

    Elmer Danenberger, a retired chief of offshore regulatory programs for MMS, told a congressional committee this month: "An industry standard should be developed to address cementing problems, how they can be prevented, and the actions that should be taken when they do occur."

    Many construction projects use concrete hardened with sand and gravel aggregate, but cement is the glue that holds it together. On federal projects, "just about everything is regulated, from the thickness of the concrete, to the strength of the concrete, to the type of aggregate that's used," said Brian Turmail, spokesman for the Associated General Contractors of America.

    Oil companies test the thickness and strength of cement in wells by shooting sound waves into the cement. This kind of test, called a sonic logging test, wasn't run on April 20 at Deepwater Horizon. A Halliburton manager said it's the most realistic way of testing the quality of the cement bond, but a BP manager said pressure tests are better and log tests are used only if there's already a sign of a problem.

   Either way, these tests are not 100 percent reliable. Sometimes, oil companies don't discover a bad cementing job until it fails.

   There can be early warning signs, though. Federal regulators have known for years that a condition called sustained casing pressure - usually gas caught between the casing and well wall - is a major problem that typically signals bad cement work.

   In the August 2007 blowout, investigators cited tests showing high casing pressures that could have indicated suspect cement work. The platform owner reported a problem to federal regulators, but nothing was done before the blowout, the report said.

   More than 8,000 of the 22,000 offshore wells on federal leases, most of them in the Gulf, show sustained pressure, according to government reports.

   This month, in a move in the works long before the Deepwater Horizon explosion, regulators wrote in the Federal Register that the oil and gas industry in the Gulf has "suffered serious accidents as a result of high sustained casing pressure, and the lack of proper control and monitoring of these pressures."

   New rules take effect June 3. But they take a conservative watch-and-wait approach and demand only routines already carried out around the industry: a management program with monitoring and diagnostic testing. If operators discover sustained pressure, they must notify MMS of plans to fix it.

   There are no new record-keeping or reporting requirements in the new rules, which are backed by industry. In the rule-making documents, regulators - long accused of being too cozy with the industry - said the regulations would cost the entire industry only $5 million, compared with the "impracticable and exceedingly costly" $2 billion alternative of fixing the wells outright.

   "Unfortunately, this is yet another crisis in a long line of accidents caused by cementing problems in drilling," said U.S. Rep. Diana DeGette of Colorado, a member of the Energy Committee looking into the cause of the blowout.

   MMS refused to answer specific questions about its cementing policies, including why it took so long to craft the pressure regulations and whether MMS has issued any citations for cement problems.

   "All of these questions are questions that we are reviewing," said Interior Department spokeswoman Kendra Barkoff.

..............my *ss.....anyways...

 That's a chart showing the world-wide cementing-in of abandoned wells by BP.

That's a chart showing the cost analysis of de-commissioning wells in the UK waters as opposed to the G.o.M.

   That's another chart showing the cost comparison.













        Here's what the American Petroleum Industry says about cementing procedures and cement types.


Class A: Intended for use from surface to 6,000 feet (1830 m) depth* when special properties are
not required. Available only in ordinary type (similar to ASTM C 150, Type I).**

Class B: Intended for use from surface to 6,000 feet (1830 m) depth, when conditions require
moderate to high sulfate-resistance. Available in both moderate (similar to ASTM C 150,
Type II) and high sulfate-resistant types.

Class C: Intended for use from surface to 6,000 feet (1830 m) depth, when conditions require high
early strength. Available in ordinary and moderate (similar to ASTM C 150, Type III) and
high sulfate-resistant types.

Class D: Intended for use from 6,000 feet to 10,000 feet (1830 m to 3050 m) depth, under
conditions of moderately high temperatures and pressures. Available in both moderate
and high sulfate-resistant types.

Class E: Intended for use from 10,000 feet to 14,000 feet (3050 m to 4270 m) depth, under
conditions of high temperatures and pressures. Available in both moderate and high sulfate-
resistant types.

Class F: Intended for use from 10,000 feet to 16,000 feet (3050 m to 4880 m) depth, under
conditions of extremely high temperatures and pressures. Available in both moderate
and high sulfate-resistant types.

Class G&H: Intended for use as a basic well cement from surface to 8,000 feet (2440 m) depth as
manufactured or can be used with accelerators and retarders to cover a wide range of
well depths and temperatures. No additions other than calcium sulfate or water or both,
shall be interground or blended with the clinker during manufacture of Class G or H well
cement. Available in moderate and high sulfate-resistant types.

.....so Halliburton should have used G or H type cement....now...let's go back to the above article for a second...

   "  In the first sign of trouble, though, the well then failed a negative pressure test, where internal fluid pressure is reduced, according to congressional testimony from a BP PLC executive. It showed different pressures in two areas, indicating an unseen leak somewhere in the well.  "

"  Oil companies test the thickness and strength of cement in wells by shooting sound waves into the cement. This kind of test, called a sonic logging test, wasn't run on April 20 at Deepwater Horizon."

  "  Oil companies test the thickness and strength of cement in wells by shooting sound waves into the cement. This kind of test, called a sonic logging test, wasn't run on April 20 at Deepwater Horizon. A Halliburton manager said it's the most realistic way of testing the quality of the cement bond, but a BP manager said pressure tests are better and log tests are used only if there's already a sign of a problem.
 ......wtf...?

...........ok....so they knew since February that there were problems...

...........on April 20th, they ran pressure tests and discovered a leak.

...........the next decision was to not perform a " sonic logging test ".....on the same day...

...........that's only because they knew it was too late.

...........pressure loss testing indicating a leak in the section of the casing made it obvious to those on-site.

............moving on....the type of test they preformed on the cement job in the Horizon well.

                        Pressure Testing Method
   " Reliance on the weight indicators may or may not be accurate at 15,000 psi "

 ..........that means the well pressure is definitly above 15k psi...

...........this next type of cement plug testing is only done in California.....why..?

                                Swab Testing Method

    " Swabbing is another method for pressure testing cement plugs. The wellbore fluid is swabbed down
until the hydrostatic fluid above the plug is below the reservoir pressure gradient of the zone
isolated by the plug. The fluid level is monitored for a reasonable time to ensure that the wellbore
fluids have stabilized. If the fluid level has notchanged, plug competency is considered verified.It should be noted that this method is used exclusively in California.  "


......next.....we know they filled the casing with seawater, after installing the cement plugs...instead of the required fluids...even though it's the law......in-between each cement plug, they are required to inject a dense fluid, to prevent pressure from building.

  "  Each of the respective intervals of the hole between the various plugs shall be filled
with fluid of sufficient density to exert a hydrostatic pressure exceeding the greatest formation pressure
in the intervals between the plugs at time of abandonment.  "

......water is a much much less dense fluid than what is normally used.....why water then ? Hhmm..?

   Perhaps the money to be made from allowing the disaster to happen,.. is much greater than the sum of money the well would produce in the long run.

......it's common knowledge now, that they drilled into the edge of the deposit thinking that pressure would be less.....that means that the overall pressure in the deposit is actually much higher than 15k psi'..

   "   Identification and reporting of sub-sea wellheads, casing stubs, or other obstructions extending above
the mud line will be accomplished in accordance with the requirements of the U.S. Coast Guard.  "

.........Coast Guard.....

.........Just to add insult to injury...

  
"   The costs associated with removal and disposal onshore of the topside facilities are significant,
accounting for 30-40 percent of the total removal costs of the installation, which in the North Sea
can range from the upper tens of million US dollars to 200-300 million US dollars. This compares to removal  disposal costs in the Gulf of Mexico in the order of 1-2 million US dollars for the relatively small installations removed to date.   "

........so...for 1-2 million ...they could have sealed the well in February, when they knew they had problems.

........now...let's look at how they normally remove cement underwater at the rig sites where they sever any cement casings attached to the sub-sea rig structure..

          Abrasive Water Jet

   "  A high pressure water jet is directed at the concrete with an abrasive garnet or copper slag mixture. The water jet bombards the structure at pressures of 10,000 to 50,000 psi and the abrasive multiplies the cutting forces.This tool typically is directed with a robotic feed assembly which controls the rate of travel for the cut and will sever the reinforcing steel along with the concrete. The method can be employed to cut concrete thickness up to several feet.  "

.......granted , sand and shale is not garnet or copper slag....but....

     "  Abrasive water jet technology has been successfully used in recent years to cut multiple string well casings. The abrasivewater jet leaves a clean, machine like cut inthe casing strings. Several different systems are in use. The pressures range from 10,000psi with a high volume output to 50,000 psi at a lower volume output. The abrasive is introduced at the cutting nozzle tip and maybe sent down a hose dry by air pressure or in a water based solution. The abrasive is propelled by the water jet after being introduced into the cutting jet, and cuts the steel and grout as it hits the target. Casing strings with void areas rather than grouted annuli have been a problem for this methodology. The water gap between casing strings dampens the energy of the water jet and causes an incomplete cut. Inconsistent abrasive delivery can also be a problem. The systems which have an air delivery of the dry abrasive grit are limited to shallow water application. The systems using a fluid delivery of abrasive have been used in water depths exceeding 600 feet. The abrasives typically used are garnet and copper slag. Some operators have been reluctant to use copper slag because of the environmental implications of the copper content; however, the level of copper present in the slag material is relatively low, and there are no restrictions its use. The most versatile aspect of this cutting technology is the relatively small toolsize, and it’s potential and historic use by remote intervention systems such as ROV’s and ADS to depths exceeding 1100 feet. The casing cuts which are completed below mudline cannot be verified visually. The tool operators have used microphones for audio feedback and hydraulic back pressure readout  to gauge whether the cut is being completed. The rotational cutting speed of the tool is set by the operator’s “feel” for the cut and by the known capability of the tool. These methods are at best, only indications of cutting performance in progress, and there have been a significant percentage of incomplete cuts on previous decommissioning work in California and in the Gulf of Mexico. The abrasive waterjet technology continues to develop and will be a popular technique for cutting applications in the future.   "

.......that's why the casing is destroyed.

......between hydrogen sulfide stress cracking in the metal well-bore casings....and the sandblasting effects of the flow of oil in the fluid column...and whatever explosive effects any previous " kill " attempts may have had......the casing has already been destroyed.

.......by omission of the facts, they reveal the lie....

.......It's simple math really. Once you have the knowledge of how things normally are supposed to be...

.......the holes in the story/the lies...are revealed by attrition......moving on.....

"    --There is hereby established in the Treasury of the United States a separate fund to be known as
the ``Ultra-Deepwater and Unconventional Natural Gas and Other Petroleum Research Fund. "

........where is that money...?................................................next

      Appraisal and Development Geoscience and Reservoir Engineering Benefit:

  "   The ultra-deepwater part of the GOM poses many geological and geophysical challenges to the exploitation of hydrocarbons. Many of these challenges are related to a combination of the ultra-deepwater environment and the presence of a regionally extensive, thick salt canopy, which overlies the prospective subsalt section. The combination of a thick water column and thick salt layer pose a formidable challenge for acquiring data and accessing resources. The environmental conditions and cost associated with the ultra-deepwater setting and deep reservoirs also impact the type and amount of data that can be gathered to increase reservoir understanding and reduce uncertainty. High drilling costs result in expensive exploration wells, sparse appraisal wells, limited sampling/production testing,

...................and development decisions based on very limited data.  "

        That comes from a section of this D.O.E. PDF on deep-water explorations....next, same doc...

     The RPSEA...The Research Partnership to Secure Energy for America, is a non-profit corporation establishment to help meet the nation's growing need for hydrocarbons.

     Here's the money they have invested in shares of various oil companies....were they given or bought...?

      ..... here's their chart showing the decrease in deep-water discoveries....which is why they let BP drill....
....after all....the discovery of this deposit was made a few years back. They knew it was risky and spent the next few years figuring out how to press for the approval, by showing various graphs and charts about the " decrease "

Sources :

http://www.gpo.gov/fdsys/pkg/FR-2008-04-15/pdf/FR-2008-04-15.pdf
http://www.mms.gov/omm/pacific/lease/Decommissioning/1998-023%20II.pdf
http://www.tsboffshore.com/images/Paper_ISOPE_2004.pdf
http://www.cbsnews.com/stories/2010/05/24/national/main6513934.shtml