Sunday, August 1, 2010
Friday, July 30, 2010
BP's Deepwater Horizon - Static Top Kill vs. Bottom Kill: Weighing the Risks
A permanent solution to the BP Macondo blowout in the Gulf of Mexico may be achieved soon but there are risks. Admiral Thad Allen announced on Monday, July 26 that a static top kill would be attempted on August 2. The schedule may be accelerated to July 31 or August 1 according to an announcement today (July 29). The sealing cap has successfully stopped the flow of oil and gas from the well and the pressure continues to build slowly. Temperature at the wellhead has not increased, and seeps near the well are mostly nitrogen and biogenic methane unrelated to leakage. BP Senior Vice President Kent Wells’ technical update on July 21 explained these findings and showed how the well will be killed.
There are risks involved in both the top and bottom kill procedures. The purpose of this post is to describe those risks. There are two risks associated with the static top kill. First, it may not work at all and second, it may rupture the casing by pumping heavy mud under pressure (“bull heading”).
Kent Wells described the static top kill as a process of continuously pumping mud into the well until the oil is pushed into the reservoir. This is clearly erroneous and must be a simplification designed for the general public. What will more probably take place is a practice called “bleed and lubricate”. Heavy mud is pumped into the well through the choke and kill lines on the blowout preventer (BOP) and allowed to sink to the bottom of the well. Hopefully, the mud will retard the flow so that some of the pressure can be bled off by producing oil to the surface for a short period. Then, more heavy mud will be pumped into the well, and the process repeated as necessary until the well contains enough mud to kill the well.
The first problem with stopping the flow from the top is that it has to be an annular kill: the flow was coming up the annulus outside the production casing. This is a very narrow space so mud will have to pumped at high pressure to achieve entry. It will initially be working against a full column of gas and oil and the shut-in pressure at the well head. On the positive side, if produced sand has accumulated in the annulus, the operation may not have to contend with the full force of the reservoir pressure in addition to these obstacles. On the negative side, the well head seals might prevent or restrict downward flow, or the pumping pressure could rupture the 22-inch casing, or reach a pressure high enough to call off the operation.
Figure 1a (based on a government document) shows that the upper part of the well bore is protected by three strings of casing (36-, 28-, and 22-inch) and cement down to 7,937 feet (measured depth below sea level). A fourth string of 16-inch casing extends nearly from the well head to where it is cemented at 11,585 feet, but it is apparently hung inside the 22-inch casing at 5,227 feet, leaving a gap of 160 feet. The 16-inch pipe has a burst rating approximately equal to the current shut-in pressure of 6,900 psi (80% of rating), but the 22-inch pipe does not meet this standard.
BP has said that the relief well DD3 plan will continue regardless of the success of the top kill operation. The main risk with a bottom kill is that it may take considerable time to accomplish. Because of the recent tropical storm, crews are just removing the storm packer today, and it will take time to re-enter and condition the hole before drilling resumes. BP estimates that the DD3 will intersect the Macondo well around August 10. Most efforts to intersect a blown-out wells require several attempts. The recent 2009 Montara blowout in the Timor Sea required four attempts that took a month after the relief well was near the blow out and cased. The bottom of the first Macondo relief well is currently located a few feet from the target at approximately 17,220 feet measured depth (based on Wells’ update and shown in Figure 1b).
The good news is that, in this case, the relief well does not, apparently, need to intersect the well exactly--it just needs to be close. Once the relief well penetrates the reservoir, enough mud can be pumped to hopefully overcome flowing pressure and kill the well. The bottom-kill option has the same annular flow path liabilities as the top kill, but it has the capacity to deliver higher flow rates directly to the reservoir. This approach will not cause significant pressuring near the well head and should not, therefore, pose a risk of rupturing the 22-inch casing.
The bottom kill option involves considerably less mechanical risk than the top kill, but time is the enemy, so the top kill makes sense. Maintaining the objectivity to abandon the operation rather than risk casing rupture will be critical.
Wednesday, July 28, 2010
Arthur Berman talks about Shale Gas: An interview in ASPO-USA's Newsletter
Posted by Gail The Actuary on July 28, 2010 - 10:40am Topic: Supply/Production
Tags: Shale Gas
Recently, ASPO-USA's newsletter printed an interview (Part 1 and Part 2) with Oil Drum staff member Art Berman (aeberman). Art is a geological consultant whose specialties are subsurface petroleum geology, seismic interpretation, and database design and management. The people doing the interview are members of the "Peak Oil Review Team," abbreviated POR in the text below. This is the shale gas portion of the interview.
POR: Can you give us your latest updated perspective on the shale gas story?
Art Berman: You have to acknowledge that shale gas is a relatively new and significant contribution to North American supply. But I don’t believe it’s anywhere near the magnitude that is commonly discussed and cited in the press. There are a couple of key points here. First the reserves have been substantially overstated. In fact I think the resource number has been overstated.
Read the rest of the interview on The Oil Drum...
Monday, July 26, 2010
My interview on CNN American Morning
Sunday, June 27, 2010
Estimated Oil Flow Rates From the BP Mississippi Canyon Block 252 “Macondo” Well
Estimates of flow rates for the BP Deepwater Horizon “Macondo” well now range from 1,000-100,000 barrels of oil per day (bopd). Initial estimates were 1,000 bopd. These increased to 3,000 bopd and then to 5,000 bopd. Now the U.S. Geological Survey believes the well is flowing 20,000-40,000 bopd but other experts believe that flow rates may be as high as 60,000 bopd. Some have even suggested rates as high as 100,000 bopd, and others as high as 250,000 bopd. The purpose of this post is to provide a calibration framework for probable flow rates.
More than 8,700 wells drilled in the Gulf of Mexico since 1996 were evaluated using publicly-available production data from the Minerals Management Service (MMS). Wells in the deepwater Gulf of Mexico dominate the highest flow rates in this data set. Approximately 4,000 wells have been drilled in water depths more than 1000 ft, and more than 700 in more than 5,000 ft of water during the past 20 years. The Macondo well was drilled in 5,067 ft of water to a total depth of 18,360 ft below sea level.
Historical Context for High Flow Rates in the Gulf of Mexico
The highest flow rate for a single well in the Gulf of Mexico is 46,467 bopd (Figure 1) based on the daily average of the peak month of production. The mean of the 50 wells with the highest oil flow rates is 27,753 bopd. A probability plot (Figure 2) of these wells indicates that the most likely case is about 27,000 bopd (P50). There is a 10% probability (P10) that a well will produce 37,000 bopd, and a 90% probability (P90) that it will produce 20,000 bopd.
There is no historical precedent for a single well producing more than 100,000 bopd. Among historical blowouts, the highest flow rates known are approximately 100,000 bopd at the Spindletop Field in Texas in 1901, the Midway-Sunset Field in California in 1910, the Long Beach Field in California in 1910, and the Lake Maracaibo Field in 1922 (http://en.wikipedia.org/wiki/Blowout_%28well_drilling%29). These were all open-hole completions drilled without casing or drilling fluid so they represent maximum unconstrained flow rates.
The BP “Worst Case Scenario” Document
An internal BP “worst-case scenario” document released June 20 has been mis-interpreted by some to indicate that the company believes that flow rates as high as 100,000 bopd are possible (http://globalwarming.house.gov/mediacenter/pressreleases_2008?id=0272#main_content). The document states that the probable range is 5,000-40,000 bopd (http://globalwarming.house.gov/files/WEB/flowrateBP.pdf). It further states that the maximum theoretical rate is 60,000 bopd. It is important to note that these values represent unconstrained, open-flow rates that might be expected after removing the BOP from the well, and are estimated to be at least 10,000 bopd more than present flow. The 100,000 bopd rate assumes that flow is occurring within the production and casing and around the annulus. It again is an unconstrained rate.
The Most Likely Case
We know that the well is producing at least 25,000 bopd because that much has been collected in a single day. It is impossible to know the flow rate until the well is brought under control and rates and pressures can be measured. It is possible that the welll is flowing at a rate 25% higher rate than any well drilled to date (60,000 bopd) in the Gulf of Mexico, but it is not likely. It is less likely that it is flowing at 110% of the rate of the highest rate well so far (100,000 bopd). It is reasonable that it may be among the highest rate wells, and was initially flowing at 40,000-50,000 bopd.
Saturday, June 12, 2010
Impacts of President Obama’s Order Halting Work on 33 Exploratory Wells in the Deepwater Gulf of Mexico
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.
Saturday, May 22, 2010
What caused the Deepwater Horizon disaster?
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.
Friday, May 21, 2010
A Guest Post by Perry A. Fischer: Are incentives to blame in the Macondo blowout?
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.
Tuesday, April 20, 2010
Nothing New in Obama Plan for Offshore Drilling
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.
Saturday, February 27, 2010
100 Years of Natural Gas Supply from Shale? It’s More Like 6 Years.
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.Friday, February 26, 2010
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
Monday, January 18, 2010
McMoran Davy Jones Gas Discovery
McMoran Exploration Company has made a significant discovery in the U.S. Gulf of Mexico that may contain 2-6 trillion cubic feet (Tcf) of natural gas reserves. The well was
drilled in 20 ft of water 10 miles south of the Louisiana coast on South Timbalier Block 168 (Figure 1). The discovery by McMoran (operator) and partners Plains Exploration & Production Company and Nippon Oil Corporation is very deep (28,125 to 28,262 feet drilling depth) but with excellent quality gas-saturated reservoir rock in the upper Wilcox Sandstone (Paleocene-Eocene--135 ft of gas pay with as much as 20% porosity and 10-20 ohm-meters of resistivity).The Davy Jones well was drilled on a large anticlinal feature with app
roximately 20, 000 acres of structural closure at Wilcox level (Figure 2). McMoran intends to continue drilling another thousand feet or so in order to evaluate the next two potential reservoir strata known as the lower Wilcox “Whopper Sand” and the Cretaceous Tuscaloosa Sandstone (Figure 3). The Tuscaloosa is a prolific producing reservoir onshore.The discovery is especially important because it provides a link between onshore Wilcox production and a series of discoveries from equivalent strata in the deep-water Gulf of Mexico including the Tiber Field announced by BP in September 2009. In 2001, the announcement of a Wilcox discovery in Unocal’s deepwater Trident-1 (Perdido) well came as a complete surprise to most of the industry. Since then, t
hese reservoir sands have been found in a 300-mile long and 50-mile wide fairway parallel to the present-day shelf margin beneath 5,000 to 10,000 feet of water, containing more than 20 fields. The stratigraphy of the undrilled gap between the onshore and the deepwater Wilcox under the coastal plain and continental shelf of Texas and Louisiana, however, has remained conjectural. This “down dip” Wilcox play has been ignored by drillers until McMoran’s test because structural complexity and deep targets involve high risk, expensive exploration.Recent discoveries of oil and gas in the deep-water offshore region of the Gulf of Mexico may have recoverable resources of up to 15 billion barrels of oil equivalent. Reservoirs consist of Paleocene to Eocene submarine fan and turbidite sandstones whose thickness exceeds 1000 feet. This sequence has been correlated with the onshore Wilcox Group. The considerable thickness, and wide areal extent of the deep-water offshore Wilcox interval challenges the common perception that most sandstone in the Wilcox was deposited within shelf and upper continental slope environments with only thin, channelized sands reaching the deep basin within shale-dominated turbidites.
For the last decade, curious geologists have struggled to explain the counter-intuitive presence of hundreds of feet of massive Wilcox sand across a wide swath of the Gulf of Mexico so far from the contemporaneous shoreline, and whether this sand trend is continuous from the onshore into the deepwater (Berman and Rosenfeld, World Oil, June, 2007). Conjecture also swirls around whether the Wilcox extends southward and underlies Mexico’s deepwater and shelves.
The news from the Davy Jones well appears to open an important new gas play in the Gulf of Mexico. McMoran’s findings will undoubtedly encourage more deep drilling for Wilcox targets in this trend. Meanwhile, the next 1,000 feet in the Davy Jones well may yet reveal the highest quality reservoir sands that correlate with the basal Wilcox “Whopper Sands” in the deepwater.
Some analysts have said that this discovery proves that concerns about peak oil and gas are unfounded. This is common whenever important discoveries are announced. It is, therefore, worthwhile to place the Davy Jones discovery in the context of broader petroleum supply, demand, cost and timing factors. While 2 Tcf is a lot of gas, it is about equal to one month of U.S. consumption during peak winter months, and we currently have an over-supply of natural gas that may persist for some time.
It is worth mentioning that the announced discovery is based on sketchy information from well logs and is does not represent an actual flow test. The reason for this incomplete data is the extreme depth, pressure and temperature of the Wilcox reservoir in this well.
Bottom-hole pressures may be as high as 25,000 pounds per square inch, by far the highest pressures known in Gulf of Mexico wells, and almost 10 times the rocket engine chamber pressure required for spacecraft liftoff. While not specifically mentioned, reservoir temperature is probably considerably more than 400 degrees Fahrenheit. Gas has never been produced at these temperatures and pressures, and may be present engineering obstacles. In addition, gas reserve volumes will shrink at surface conditions. There is also a possibility that the gas will contain carbon dioxide, which will reduce the volume of commercial gas and present a disposal problem.
The Davy Jones well has cost almost $200 million so far, and development drilling is expected to cost $1.5-2.0 billion. Production facilities will add to that cost. There are few rigs in the world that are capable of drilling at these depths and temperatures, so Davy Jones will have to stand in line with all of the deep-water Wilcox discoveries in the Gulf of Mexico and the pre-salt fields in Brazil’s Santos Basin for rig availability. The earliest estimates for first production are in 2013.
At the same time, the apparent discovery opens a new trend in the Gulf of Mexico that could contain considerable new reserves. The Davy Jones discovery announcement comes at a time when few oil and gas companies are pursuing objectives other than shale plays. Fortunately, there are wildcatters that are willing to pursue these high-risk, high-reward plays, this time with apparent success. Stay tuned because this is a promising development.
