Impacts of President Obama’s Order Halting Work on 33 Exploratory Wells in the Deepwater Gulf of Mexico

The Presidential Order does not affect the 4,515 shallow-water wells, and it does not affect 591 producing deepwater Gulf wells.

Roughly 33% of nation’s domestically produced oil comes from the Gulf of Mexico, and 10% of the nation’s natural gas.

80% of the Gulf’s oil, and 45% of its natural gas comes from operations in more than 1000 feet of water – the deepwater (2009 data).

Suspension of operations means roughly 33 floating drilling rigs – typically leased for hundreds of thousands of dollars per day – will be idled for six months or longer.

$250,000 to $500,000 per day, per rig – results in roughly $8,250,000 to $16,500,000 per day in costs for idle rigs;
Secondary impacts include:
• Supply boats – 2 boats per rig with day rates of $15,000/day per boat - $30,000/day for 33 rigs – nearly $1 million/day
• Impacts to other supplies and related support services (i.e., welders, divers, caterers, transportation, etc.)

Jobs –

Each drilling platform averages 90 to 140 employees at any one time (2 shifts per day), and 180 to 280 for 2 2-week shifts
Each E&P job supports 4 other positions

Therefore, 800 to 1400 jobs per idle rig platform are at risk
Wages for those jobs average $1,804/weekly; potential for lost wages is huge, over $5 to $10 million for 1 month – per platform.
Wages lost could be over $165 to $330 million/month for all 33 platforms

Secondary impacts: Many offshore workers live in Louisiana. The state is going to see a decrease in income taxes and sales taxes that would normally be paid by those employees. (The state does not collect a sales tax on oilfield supplies and equipment used offshore.)

Companies Impacted:

Oil Companies Impacted

Shell has seven (7) exploratory wells that will be impacted

Others include:
Chevron (4)
Anadarko (3)
Marathon (2)
Noble Energy (2)
Eni US Operating Co. (2)
ATP Oil & Gas (2)
Statoil (2)
ExxonMobil (1)
Petrobras America (1)
BHP (1)
BP (1)
Kerr McGee (1)
Murphy (1)
LLOG (1)
Newfield (1)
Hess (1)

The 33 gulf wells where operations are suspended were the ones inspected immediately after the Deepwater Horizon blowout (per Interior Secretary Ken Salazar); in those inspections, “only minor problems were found on a couple of rigs”. Salazar believes “additional safety measures can be taken including dealing with cementing and casing of wells and significant enhancements and redundancies of blowout prevention mechanisms. Although these rigs passed the inspections, we will look at standards that are in place.”

Longer term impacts include

Idle drilling rigs in the Gulf could mean that they will be contracted overseas for work in other locations, and if/when the halt is lifted, rigs will not be available for completing the work in the Gulf.

Loss of tolls on LA Highway 1 resulting from loss of traffic related to deepwater operations; tolls go directly to retiring the bond debt for construction of LA Highway 1 improvements, and if those tolls are lost, the state of Louisiana – as the other responsible party on the bonds - will have to pay to retire that debt, meaning loss of funding for some other programs in the state’s budget.

A 6-month halt in new drilling would defer 80,000 barrels/day, or 4% of 2011 deepwater Gulf of Mexico production. (Wood MacKenzie)

Higher drilling costs might jeopardize exploration in frontier areas. More immediately, estimates are that seven current discoveries could be rendered sub-economic, putting U.S. $7.6 billion in future government revenues at risk. Proposals to increase the cap on oil companies’ liability for oil spill damages to U.S. $10 billion could exclude U.S. independents from offshore Gulf of Mexico activities. (Wood MacKenzie)

Since these wells are not yet producing, there is no decrease in the available oil supply. However, it could lead to a decrease in the availability of domestic oil, and it is hard to tell how commodity speculators are going to respond over the next six months; there is the possibility for driving oil prices to levels well over $100 per barrel.

Prepared May 28, 2010, based on most recent data available; will be updated as needed.

What caused the Deepwater Horizon disaster?

See the full post on The Oil Drum: http://www.theoildrum.com/node/6493#more

The blowout and oil spill on the Deepwater Horizon in the Gulf of Mexico was caused by a flawed well plan that did not include enough cement between the 7-inch production casing and the 9 7/8-inch protection casing. The presumed blowout preventer (BOP) failure is an important but secondary issue. Although the resulting oil spill has potentially grave environmental implications, recent efforts to limit the flow with an insertion tube have apparently been effective. Continuous efforts to slow or stop the flow include drilling two nearby relief wells that may intersect the MC 252 wellbore within 60-90 days.

A Guest Post by Perry A. Fischer: Are incentives to blame in the Macondo blowout?

We now know, or at least we think we know, the causes of the BP Macondo blowout. Starting from the highest “top view” downward, the first cause may have been bonus incentive. “Better, faster, cheaper” has been the mantra of NASA for more than a decade. But “Two out of three ain’t bad” is not a good song. When one is incentivized to do things faster and cheaper in the corporate arena, it is automatically better, though not necessarily safer. When Shell executives were paid bonus for reserves additions, the result was bogus reserves and the resulting scandal and industry-wide write-down. Bonus is routinely paid for faster and cheaper across many industries. Could it have played a role in the case of the Macondo well disaster?

The revelation that the company used only 50 barrels of foamed cement (TudorPickeringHolt webcast) on the most critical part of the well is mind-boggling. Also, why they chose to use N2 foamed cement across a formation (that was known to contain a supercritical slush of mixed fluids whose behavior is difficult to predict) is a bit perplexing too. Perhaps it was to prevent the gas-cut cement that has been a problem on deep, high-pressure wells, but how would light, foamy cement do that?

But the 50 barrels number seems to be missing a zero, almost like it’s a typo, reminiscent of NASA’s infamous “Was that in meters or feet?” mistake that caused more than $200 million to crash into Mars. BP took foolish risks in the interest of time-saving that I cannot explain. You don’t even need your red Halliburton book to know that with 50 barrels, BP was planning to cement, at best, a short amount over the shoe of the previous casing string, just above the producing zone. This is even more perplexing given that the zone was known to have washouts. What was the thinking here?

As perplexing as the above decision-making was, BP decided not to run a Cement Bond Log (TudorPickeringHolt webcast). This might not be so bad on a straightforward infill well at modest depth and pressure, but this reservoir had already “eaten” one drill string on the first well, which had to be abandoned. There was a Schlumberger Unit and personnel on the rig. They were not utilized. I’ve run CBLs. Even a crummy, short CBL would probably have at shown bond quality and channeling (if present) and would certainly have shown the Top of Cement; in this case, with minimal cement, it would have been extremely important to know the location of the TOC.

Adding to the puzzle was the fact that there were indications that the wellbore was taking in gas. According to the log record (http://energycommerce.house.gov/Press_111/20100512/Halliburton-Last.Two.Hours.Chart.PDF) it appears that the SPP (the circulating pressure) starts to decrease at about 8 pm as part of the riser mud displacement. The displacement continues for about 45 min. From 8:00 to 8:08, the pump rate is steady, but SPP is gradually rising. Pumps are shut off for the next hour. SPP is increasing. At 9:14, pumps are started and shut off again at 9:18. SPP is significantly increasing. Pumps are re-started and from 9:20-9:30, the SPP is considerably higher than at previous flow rates. At least an hour before the blowout, the crew would have to know that they were dealing with a potentially dangerous situation. It appears that the crew may have had time to reroute the flow to the gas blow-by pipe, which can be seen on the photos, but wouldn‘t the BOP be closed, evacuation (or at least minimal personnel) on the drill floor and other necessary emergency measures be taken? Were they? The log is hard to explain. Something must have been done, but what was it, and why was it so inadequate? Was it because of the visiting top brass?

We also know that the BOP had a weak battery, causing one of its electrical modules to go down (the other one was functioning). Also, during a test, 15 feet of drill pipe was stripped through a BOP pipe ram, causing many chunks of the ram’s rubber to appear in the mud pit, and get fished out and presented to a Transocean supervisor (eyewitness, 60 Minutes interview). Yet the BOP was not pulled.

Finally, why was the riser displaced of its 14.5-lb mud BEFORE the top cement plug was installed--a reverse order operation? The answer is it made better use of the Waiting On Cement time, shortening the well-construction time. In fact, all of these bad decisions shorten the well-construction time and enhance any performance bonus that is paid. Else, they do not make basic well-construction sense in their own right.

We may never know the exact route that the gas took--it might not be very important in any case, give the appalling sequence of decisions (unless, of course, the BOPs are found to have parts from the top casing seals stuck in them). It could have come through the bottom plug, through some casing joint above that plug into the wellbore, or straight up the production casing annulus through a failed casing hanger seal assembly into the BOPs.

Oddly, MMS just made its new SCP (Sustained Casing Pressure) ruling final this month--a testament to just how ineffective MMS regulation can be. Thirty years ago, when we had about a hundred wells with SCP in the annuli, we knew we had a serious problem. So we did nothing meaningful in the way of cement or well construction, in order to save money, and over the next decade or so, the problem grew to “Houston, we have a problem” proportions of 1000 wells. Again, we rearranged the paperwork and asked MMS for more Casing Pressure Exemptions, which were usually granted. So the problem grew to 8,000 wells (a conservative MMS estimate).

Now, with the guidance and help of just two entities, BP and API, new regulations come into force that promise not to cost hardly anything, but do require new paperwork and, most importantly, require more monitoring of casing pressure annuli, and still allow a strung-out timeframe in which to act, if ever, including Casing Pressure Exemptions. The existing regs had already been weakened to allow for SCP of 20% of casing design. The new API RP90 that MMS adopted speaks only of SCF “management.“ In short, the new MMS regs ensure that there will be 12,000 wells with SCF problems, made worse as water depths and pressures increase.

One thing MMS was right about, SCP “…represent a clear hazard to the safety of personnel or the environment.” The BP well design and execution, if completed, would likely have been a future SCP problem--it just happened a lot sooner. If MMS did, as reported on some blogs, grant BP an exemption to the normal sequence of well construction on Macondo, it would not be a surprise--MMS overwhelmingly says “yes” to requests from oil companies (I don’t know the percentage, but I’ll bet it’s well over 90%. In the 50 or so MMS requests that I‘ve been privy to, all of them were granted).

According to the Wall Street Journal (http://www.rigzone.com/news/article.asp?a_id=92962), in the last 10 years, MMS enforcement cases that resulted in penalties were 66 in 2000 (a high point) to just 20 last year (it‘s lowest number). A report by the Interior Dept. Inspector General in 2000 found that MMS seldom referred safety or environmental violations to the Justice Department for criminal prosecution, even when it should have done so. Rig inspections all fell, according to agency data, to 760 in 2009, down from 1,292 in 2005. Increasingly, MMS has shifted toward a policy of industry self-regulation. The MMS in a 2005 rule change pointed to a older law that “encouraged federal agencies to ‘benefit from the expertise of the private sector’ by adopting industry standards, said the WSJ article.

All told, it seems difficult to find the common thread to the bad decisions of a minimal, foamy cement job, no CBL confirmation of placement, premature displacement of drilling mud, ignoring known problems with the BOP, and a willingness to disregard data and forge ahead, except that they all speak to hurry up and “get ’er done.” All of these were human errors, not mechanical ones. The real shame is that if even one of these decisions were made differently, this disaster probably would not have happened.

Nothing New in Obama Plan for Offshore Drilling

In early April, the Obama Administration announced that it will expand offshore exploration and development to reduce dependence on foreign oil. The plan that was announced is, in fact, more restrictive than what was already in place, and will have no near- or mid-term impact on our need to import oil. It maintains the status quo by allowing leasing in the eastern Gulf of Mexico and offshore Virginia, and by allowing drilling in certain areas offshore Northern Alaska, but it closes the Bristol Bay area offshore southern Alaska. All areas in the Pacific Ocean off the coasts of California, Oregon and Washington remain closed.

The portion of the eastern Gulf of Mexico that is offered for leasing in the government’s plan is limited to areas more than 125 miles offshore that are mostly in water depths of 6,000 feet or greater (Figure 1). While the administration describes this as a development area, it is a high-risk, ultra deep-water wildcat province. Sixty-two wells were drilled in shallower areas of the eastern Gulf before the drilling moratorium, and the only prospective area found so far is the shallow-water Destin Dome region off the Alabama coast where reserves are estimated to be 2.7 trillion cubic feet of gas (equal to about 1.5 months of US natural gas consumption). The geology of the eastern Gulf of Mexico is different from the traditional producing area of the central and western Gulf. While it contains legitimate petroleum systems, it is a relatively high-cost, high-risk area.

The area of the Atlantic coast that is included in the government plan is offshore Virginia (Figure 2). The Atlantic margin of the U.S. was drilled and evaluated before the area was closed to exploration in the 1980s, and the results were dismal. More than 50 wells were drilled, and only a few wells in the Baltimore Canyon area off the coasts of New Jersey, Maryland and Virginia had any indications of petroleum. A few wells tested showed that natural gas could be produced at rates that would probably be commercial onshore today, but not 100 miles offshore.

In frontier areas like the Atlantic Margin and Eastern Gulf of Mexico, big fields are commonly discovered early in the exploration cycle because industry identifies and drills the largest, most obvious features first. The fact that approximately 50 largely unsuccessful wells have been drilled in each of these areas is discouraging. The Atlantic Margin seems to be an area where any hydrocarbons that are found will be natural gas rather than crude oil, based on geochemical analysis to date. While that is not a completely negative factor, further exploration there does little to change our dependence on foreign crude oil, and we currently have abundant supplies of onshore natural gas that can be found and developed at considerably lower cost.

On the positive side, the Atlantic Margin and eastern Gulf of Mexico are huge areas where important discoveries may have eluded early exploration efforts. Neither of these regions has been evaluated using modern seismic methods that could yield a different view of its potential for producing natural gas or oil.

As someone who works in the exploration and production business, I am in favor of opening these areas and letting industry decide if they have merit. At the same time, it is important to be objective. Under the most favorable scenario, it will take many years to acquire and interpret the necessary seismic and geochemical surveys that precede drilling. If discoveries are made, appraisal drilling, economic analysis, and development planning will require more time. Infrastructure adds yet another layer of time and complexity. Evaluation of large oil and gas projects worldwide commonly takes at least six years from discovery to first production. High-risk, capital intensive oil and gas exploration cannot be expected to produce quick results.

100 Years of Natural Gas Supply from Shale? It’s More Like 6 Years.

The widespread belief that there is 100 years of natural gas supply in the U.S. because of shale plays is incorrect. The Potential Gas Committee (PGC) estimated 1,836 Tcf of technically recoverable gas resources for the U.S. in its report released in June 2009. Along with proved reserves of 238 Tcf, there are 2,074 Tcf or 85 years of total supply based on current demand of 25 Tcf per year (EIA). The contribution of shale gas is 661 Tcf, or about one-third
of the total, technically recoverable resource (Figure 1). The PGC estimate of probable resource volume is 441 Tcf, or about 18 years of supply. Shale gas accounts for one-third of that amount, or 147 Tcf, which is about 6 years of supply at current U.S. demand. That is a lot of gas, but far less than the volume that is routinely stated in the press or by shale-gas advocates. These public statements often do not take high decline rates or anticipated future demand growth into account.

ExxonMobil’s Acquisition of XTO Energy: The Fallacy of the Manufacturing Model in Shale Plays

See the original full post on The Oil Drum:
http://www.theoildrum.com/node/6229

Posted by aeberman on February 22, 2010 - 8:26am
Topic: Geology/Exploration
Tags: exxonmobil, natural gas, original, shale gas, xto energy [list all tags]

Most analysts believe that the ExxonMobil acquisition of XTO Energy (XTO) represents a dramatic shift in strategy by the premier exploration and production (E&P) company, and a validation of shale plays. It is neither. The move represents a considered and deliberate choice that acknowledges diminished opportunities for the oil giant to add and replace reserves. The acquisition acknowledges that natural gas is the only viable short-term solution to North America’s energy needs, and that demand will grow. It implies that ExxonMobil believes that higher natural gas prices will be part of that energy future. It presumes that the company can improve on the flawed manufacturing model that has dominated the way that U.S. shale plays have been pursued.

ExxonMobil’s acquisition of XTO only seems dramatic to those who have not paid attention to the company’s strategy and change in project mix over the past decade. Its portfolio consisted of 75% unconventional resources before the XTO acquisition (Figure 1) with a strong emphasis on tight, acid and sour gas, LNG, and heavy oil projects. Tim Cejka, President of ExxonMobil Exploration Company, told The Wall Street Journal last year that his company has been “bullish” on shale plays since 2003 (Wall Street Journal, July 13, 2009). David Rosenthal, ExxonMobil Vice President of Investor Relations recently said, “It’s not a strategic shift” (Houston Chronicle, February 2, 2010).

See the rest of the original full post on The Oil Drum:
http://www.theoildrum.com/node/6229

Implications of Exxon Mobil acquisition of XTO Energy Presentation February 2010

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