BP officials insist safety was a top priority on the Macondo drilling project more than 40 miles off the coast of Louisiana, but there were plenty of reasons for the oil giant to want to cut corners to save time and money.

The drilling rig cost BP about $530,000 per day to lease, not including the daily rates for the many contractors on board. And the project was delayed repeatedly, having started in October 2009 by a rig that was later damaged by Hurricane Ida.

Later, while drilling with the rig Deepwater Horizon, the project lost more than a week when equipment became stuck at around 13,000 feet, forcing the crew to pull back, cement over a section and drill a wide path around it.

The “time is money” mantra would hardly have been unique to the Deepwater Horizon, or even to the oil industry, said Gregory McCormack, director of the University of Texas' Petroleum Extension Service.

But in the reams of documents and hours of testimony about the accident that have come out in the past month there are a number of items that can be seen as examples of BP trying to cut costs.

Under pressure

According to a January 2010 BP well plan the Houston Chronicle obtained, the company had budgeted nearly $98 million for drilling and completion of the well.

With the exception of money spent before the rig actually started drilling into the seafloor, the largest portion of that budget — about $18 million — was expected to be spent once the well was drilled to its full depth.

Companies feel particular pressure to shorten such “non-rotating” time when drill bits aren't turning but the clock is still running on the rig. That may help explain one of the first shortcuts noted by workers on the rig — the decision to move quickly from circulating drilling mud in the well to pumping in seawater.

Truitt Crawford, a roustabout who worked for the rig's owner, Transocean, told Coast Guard officials in a written statement about such pressure.

“I overheard upper management talking, saying that BP was taking shortcuts by displacing the well with saltwater instead of mud without sealing the well with cement plugs,” Truitt said in a witness statement obtained by the Chronicle.

The cement plugs would sit inside the bottom of a long section of pipe that was supposed to serve as the conduit for oil and gas to the surface when the well started producing.

But even before the cement plugs were put into place, there were other elements of the well design that were less costly — and could have compromised safety.

No secondary barrier

The final stretch of piping that ran from the wellhead just under the seafloor all the way into the oil reservoir was cemented in place at the very bottom.

The cement barrier, however, only went several hundred feet up and did not reach the next section of larger pipe above it.

This meant there was no secondary barrier between the reservoir and the wellhead, so if any gas leaked through the cement it would have an unobstructed path all the way to the surface.

A secondary barrier isn't required in federal well design standards, but as the Chronicle reported earlier this week, taking the time and spending the money to install one would have provided another level of safety.

There are other indications that the cement job may have done with an eye toward savings.

The final section of the production casing was supposed to be centered in the wellbore — the area carved out of the earth by the drill bits — by special brackets known as centralizers. Keeping the pipe centered ensures that cement is distributed evenly all around and isn't thinner on one side.

The final section of the production casing was supposed to be centered in the wellbore — the area carved out of the earth by the drill bits — by special brackets known as centralizers. Keeping the pipe centered ensures that cement is distributed evenly all around and isn't thinner on one side.

The original well plan called for 21 centralizers, but it was discovered that 15 of the centralizers were not the ideal design for the job.

Rather than wait for the right type of centralizers, the decision was made to use just the six on hand that worked.

BP also decided not to not run a final, time-consuming test on the cement job — a cement bond log — in which a device is lowered into the well that using sonic signals to determine how well the cement has adhered to the pipe.

Oil field services firm Schlumberger was hired by BP to provide a variety of services on the Deepwater Horizon rig and had a crew on standby on the rig from April 18 to 20 for any additional tests.

The team, however, was not called on for the bond log so they left the rig the morning of April 20, according to Schlumberger.

Alleged argument

A number of witnesses in hearings before a joint Coast Guard/Minerals Management Service panel this week said BP and Transocean officials argued about last-minute procedures and tests related to the well's integrity.

But one of the Transocean officials said to be at the center of the arguments, Jimmy Harrell, said there was no heated debate, just a discussion about BP's plans to not perform a particular pressure test on the well. BP officials eventually decided to do the test.

There is always a “natural conflict” between oil companies paying the bills for an offshore drilling operation and the owner and operator of a rig doing the work, said Carl Smith, a captain for a rig owned by Diamond Offshore, who was called as an expert witness during the Coast Guard hearings.

But Steve Tink, BP's health and safety team leader for drilling and completions in the Gulf of Mexico, said the company's drive to control the massive costs of drilling a deepwater well is not in conflict with promoting safe operations.

“Our basic philosophy on that is that a safe rig is an efficient rig,” he testified.

Brett Clanton in New Orleans and Jennifer Dlouhy in Washington, D.C., contributed to this report.

tom.fowler@chron.com