SM Energy Power River


  • SM Energy has further increased its position in the over-pressured Frontier Sandstone oil play in the Powder River Basin.
  • SM provided an update on existing well performance, which is very encouraging.
  • The company’s position has the scale and quality to make material difference for the stock in the event of continued success.
  • SM’s delineation program may provide a fresh impetus for other operators to accelerate their efforts.

In the operating update that SM Energy (SM) discussed last week, the continued build-out of the company’s acreage position in the Powder River Basin (“PRB”) was perhaps the most notable development. This emerging play has gained critical mass in SM’s portfolio, and the company is ramping up its delineation effort. SM now controls ~122,000 net acres prospective for the Frontier (the operator’s primary target in the PRB’s stack of multiple oil-bearing formations). The acreage, which is blocked up and mostly operated, is located within what SM considers to be the most prospective over-pressured portion of the trend.

As a horizontal oil province, the PRB is not new. Operators have successfully produced from various sandstone formations in this basin, mostly from vertical wells. However, the greatest potential appears to be associated with a number of emerging horizontal oil plays. Two years ago, for example, PRB was heralded by Chesapeake Energy (CHK) as one of the most promising liquids-rich opportunities in its portfolio, mostly in connection with the Niobrara Shale play. Several other operators, such as Devon Energy (DVN) and EOG Resources (EOG), have also been working on cracking the code of this multi-stack resource. However, progress has been disappointingly slow.

The acceleration of SM’s drilling effort in the Frontier and Shannon may help open a new chapter in the PRB’s development. From the SM stock’s perspective, the company’s leasehold in the area now has the scale and quality to “move the needle” and, in the event of success, could be very material to the company’s stock price.

Bolt-On Acquisitions In The Powder River Basin

According to SM’s press release, the company has recently agreed to acquire approximately 21,000 acres (net of acreage trades) prospective for the Frontier, Niobrara, Shannon and Sussex formations for roughly $100 million in cash. The acquired acreage is located predominantly in Converse County of Wyoming, and enhances the company’s existing position. Once the transactions are completed, SM will have a total of 161,000 acres in the Powder River Basin, 122,000 of which will be prospective for the Frontier.

A good portion of what SM is buying are additional interests in spacing units in which the company already has some interest. (“It’s a direct bolt-on to acreage we had, plus some nice fill-in around what we have.”) This will allow SM to operate more of its acreage and control the pace of development and capital deployment. After the closing, SM’s working interest in the acreage should increase to ~55%. As shown on the slide below, SM’s acreage in the PRB will extend over a trend area roughly 30 miles long, making SM one of the dominant lease owners in the Basin, alongside Devon and Chesapeake.

(click to enlarge)

(Source: SM Energy, April 2014)

This is not SM’s first significant acquisition in the PRB. A year ago, SM acquired approximately 40,000 net acres from QEP Resources (QEP) for $145 million, increasing SM’s previously disclosed position to approximately 105,000 net acres. SM planned to focus initially on the Frontier, Sussex and Shannon formations, and estimated combined resource potential on its acreage at 90+ MMboe. Since then, SM has been active in expanding its leasehold in the area, as is visible from a comparison of the map above to the year-old map below.

(click to enlarge)

(Source: SM Energy, April 2013)

The Implications

The most recent acreage acquisitions translate into approximately $4,800 per undeveloped acre on average, one of the highest prices paid in the play so far. As a reminder, SM commented in the past that it had paid ~$1,500 per undeveloped acre in the QEP transaction (net of existing production). In addition, some of the company’s leaseholds are longtime legacy acreage that the company had held by production and which is “very, very low-cost.”

The acquisition sends positive signals:

  • The relatively high price that SM agreed to pay implies the company’s increased confidence in the play.
  • The acquisition coincides with the acceleration of the drilling program to three rigs from two rigs. (SM now expects to drill 11 wells in the play in 2014, up from 8 wells planned earlier.)
  • Production history from existing wells is highly encouraging.
  • The non-consent rate in new wells has declined, according to SM.

Well Results

The slide below shows the most recent cumulative production plots for SM’s long lateral operated wells in the Frontier formation, which is the primary target. SM commented that the wells are all performing better than the company’s threshold. SM’s most recent long lateral well, the Blackjack, had a 2-stream peak 30-day IP rate of 917 boe/d. SM is currently flowing back a 5,000-foot lateral well, which is “also looking good,” according to management, but doesn’t have enough producing days yet to calculate a 30-day rate.

(click to enlarge)

(Source: SM Energy, April 2014)

Overall, Frontier results in the play have been encouraging, notwithstanding high well costs. A year ago, SM provided initial results for three Frontier long-lateral wells, one operated by SM and two partner wells, that had 30-day IP rates of 927 boe/d; 1,418 boe/d; and 1,734 boe/d. SM’s long-lateral (1,280-acre drilling unit) type curve implied a 1,067 Mboe EUR (65% oil). Since then, SM has added two new operated Frontier horizontals that had 30-day IP rates (2-stream) of 1,408 boe/d and 917 boe/d. SM is currently using a 850 Mboe “benchmark curve,” which represents a ~20% downward revision to the initial “benchmark.”

Most importantly, the wells have shown very positive production trajectories:

  • The first well, the Dandy State 3774-16-21-1FH, has been online for 15 months, producing over 250 Mboe. The well has tracked above the type curve.
  • The two more recent wells, the Loco Fed 4076-9-4-1FH and Blackjack Fed 3774 27-22-1FH, are also performing at or above the type curve. The Loco Fed produced ~130 Mboe in about seven months.

The decline rates exhibited by these wells are relatively low and give hope for high EURs. I must emphasize that the Frontier is a sandstone formation.

Well Costs May Decline As The Play Matures

SM indicated that its drilling results in the Frontier are already economic.

For the long laterals, the company’s recent well cost has been about $16 million. However, SM thinks it can drill those wells for $14 million, assuming the same frac design that it currently uses (management noted that they may need to step up the frac size, which could drive the cost a little higher, but would potentially generate better wells as well).

SM also estimates shorter lateral well costs in the $9-$11 million range. The cost for the most recent 5,000-foot lateral was about $11 million.

SM estimates that Frontier wells, using the 850 Mboe EUR assumption and current $16 million well cost, exceed return hurdles (PV-15%/Investment of 1.2x, or ~25% rate of return). Using actual production trajectories, the wells are performing solidly above these hurdles.

SM commented that it will continue to plot its well performance against the 850 Mboe EUR comparison benchmark – which may prove conservative – until it has enough wells to be able to present a reasonable type curve.

The wells drilled are exceeding the company’s hurdle over a big area. However, as I noted, this play is 30 miles from north to south, and three well results that are shown on the cumulative production plot are 28 miles apart. SM indicated that the underlying geology is not homogeneous.

We got a long way to go here before we can divide this [trend area] up into type curve areas and really give you a lot of definition about those various areas. The areas are different. And over time, we’ll get more — we’ll cut this acreage down and give you more details, but this is the best we can do at this point.

Other Targets – Shannon and Sussex

In addition to the Frontier, SM is also testing other formations in the stack, including the Shannon, which is believed to be the next most promising target. Almost all SM’s acreage has additional either Shannon or Sussex potential. The Shannon, which SM believes has historically been under-stimulated, is particularly promising.

To date, operators have drilled a number of wells in the Shannon, but most of them have been marginally economic or sub-economic. Last year, SM completed a relatively successful Shannon well, the Bridger, that had an IP rate of about 500 boe/d. SM commented that the well was “reasonably economic.” The company believes that Shannon wells drilled in the area to date may have performed below potential, due to the insufficient size of the frac jobs. The company’s management commented:

The last well we did was a pretty encouraging [IP] number, given what we pumped… It was… not as exciting as the Frontier to us at this point, but I think there’s a lot of potential in the Shannon. When I look at them [the existing well results], I just say nobody has really gone out there and pumped as good a job as you can possibly pump… So I look at it as a significant upside to the Frontier in a lot of potential locations, but it’s certainly unproven at this point that it can be as economic as our Frontier program.

I should note that the well cost in the Shannon is expected to be slightly lower than in the Frontier.

In addition to the Frontier and Shannon, other zones are also known to be potentially productive and economic. For example, the Sussex is a shallower formation, which has been a significant vertical oil producer. In the past, QEP estimated EUR potential for short (5,000-foot) laterals in the 300-450 Mboe range.

Activity Level To Increase

SM is stepping up its activity level to accelerate the delineation of its PRB acreage. The company is currently running two operated rigs, and will be adding a third rig later in this quarter. The company is focused on improving drilling performance and refining completion designs, and adding a third rig should help SM accelerate that process.

SM now expects to complete 11 operated wells in the Powder River Basin in 2014, up from the 8 the company had planned for in its original budget. Several of these wells target the Shannon.

SM views its next several Frontier wells as important ones, as they target the area in the center of the company’s acreage position. With continued success, SM expects that the rig count may further increase in 2015. The company has already received 16 drilling permits. SM commented that the PRB program continues to generate encouraging results, and may add to what the company believes can be a significant new resource play for the company

The slide below shows new well locations to be drilled in 2014 (please note, three locations have been added to the 2014 program that are not shown on the map).

(click to enlarge)


It is still premature to say that SM’s entire acreage position “works” for the Frontier – further delineation is obviously required. But the wells drilled so far by SM and offset operators already have shown commercial success and, importantly, have been fairly consistent, which is encouraging.

The increase in drilling activity is particularly important. The Powder River Basin is characterized by a difficult and often slow permitting process (there is a lot of federal acreage). Infrastructure can be a limiting factor too. SM has been working on setting up drilling units and obtaining permits for its current program for over a year. The effort is clearly paying back. Management commented that the company is “well ahead on permitting.”

If SM’s 2014 delineation program proves successful, it may create impetus for other operators to step up drilling effort in the PRB.

SM’s program may create a positive read-across to other stocks. Bill Barrett (BBG) is one that immediately comes to mind. Bill Barrett owns significant interest in the PRB (68,000 net acres and ~1,330 boe/d of production), and is currently marketing the asset.

Disclaimer: Opinions expressed herein by the author are not an investment recommendation and are not meant to be relied upon in investment decisions. The author is not acting in an investment advisor capacity. This is not an investment research report. The author’s opinions expressed herein address only select aspects of potential investment in securities of the companies mentioned and cannot be a substitute for comprehensive investment analysis. Any analysis presented herein is illustrative in nature, limited in scope, based on an incomplete set of information, and has limitations to its accuracy. The author recommends that potential and existing investors conduct thorough investment research of their own, including detailed review of the companies’ SEC filings, and consult a qualified investment advisor. The information upon which this material is based was obtained from sources believed to be reliable, but has not been independently verified. Therefore, the author cannot guarantee its accuracy. Any opinions or estimates constitute the author’s best judgment as of the date of publication, and are subject to change without notice.

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Geothermal Sources

Geothermal Sources
By Debbie Pollitt, eHow Contributor
Print this article
Nearly 90 percent of Icelandic residents use geothermal energy for heat.
Geothermal energy is literally the natural heat of the Earth — earth (geo) heat (therme) — and a renewable resource that can be used to heat buildings and generate electricity. The heat is continuously produced deep within the Earth’s core, will never run out and can be redeemed as steam or hot water. U.S. geothermal projects rose by 12 percent in 2010 and, as of 2011, nine states produce geothermal power.
Billions of years ago when the Earth was forming, large amounts of energy were caught in the middle of the planet, bonding molecules of iron and nickel together to make the Earth’s core. The core is about 4,000 miles beneath the surface on top of which are two more layers — the mantle and the crust. High temperatures are continuously produced and the deeper the layer within the Earth, the hotter the heat. Geothermal energy comes from the intense heat and is caused by the slow decay of radioactive particles, a process that happens naturally in all rocks.
Hot Spots
The Earth’s crust keeps the heat of the mantle beneath the surface but when the heat becomes so intense that it breaks through the crust, it creates patches of geothermal energy known as hot spots. Hot spots can be in the form of volcanoes or geysers. Yellowstone National Park, for example, is home to many geysers, the most famous of which is Old Faithful. Cracks and openings in the crust create ventilation points ensuring that the mantle is able to keep the Earth’s surface continuously heated. This kind of geothermal energy emerges less explosively in the form of steam, creating springs and wells of heated water.
Geothermal energy is potentially everywhere but finding it is easier said than done. Volcanoes, springs and geysers are useful indicators of geothermal reservoirs and scientists may find clues by analyzing local soil and water sources but otherwise the most reliable way to locate them is to dig deep and drill. The world’s hottest geothermal area is the Pacific Ocean’s “Ring of Fire” while America, New Zealand, Iceland and Indonesia are also countries rich in geothermal sources. U.S. geothermal systems include the Geyser’s region of Northern California, Southern California’s Imperial Valley and the Yellowstone areas of Idaho, Montana and Wyoming. Hawaii, Arkansas and Texas also have significant geothermal activity.
Advantages of Geothermal Energy
It’s a very clean source of energy as nothing has to be burnt to produce the steam to turn the turbines. Using geothermal energy produces fewer greenhouse gas emissions than other energy sources. It is available around the clock, every day of the year and is capable of reducing America’s reliance on foreign oil imports. Geothermal plants can produce cheap electricity and although the initial construction and start-up costs are high, the long-term costs are low compared to conventional power plants. There are no transportation costs and the supply is reliable, predictable and stable.
Read more: Geothermal Sources |

Oil Services

Oilfield services
The unsung masters of the oil industry
Oil firms you have never heard of are booming
Jul 21st 2012 | ABERDEEN |From the Economist print edition
A TECHNIQUE called “directional drilling” has transformed the energy business. Fifteen years ago the best drillers could force a well-shaft into a gentle arc. These days shafts can be drilled vertically to a depth of several kilometres—then made to turn sharply and continue horizontally for up to 12km (or 7 miles). Will Grace of Schlumberger, an oilfield services company, likens it to dropping a plumb-line from the top of the Empire State Building and then guiding it through the rear and front windscreens of every car parked in the nearby streets.
Such technology vastly increases the area one rig can cover (see diagram). For an illustration, Mr Grace points to squiggles and shadings on a computer screen in one of the 34 offices Schlumberger operates in Aberdeen, a Scottish oil city. The lines show the progress of a well completed for a Canadian oil firm a few hours earlier. It is 13,000 feet (4,000 metres) deep and has been brought to a halt 6,500 feet horizontally away from the rig, within three feet of its target.
Instruments in the “drill-string”—as formerly inflexible steel drill-shafts are now called—are meanwhile transmitting dozens of additional measurements: of the radioactivity of the surrounding rock, its resistivity to electromagnetic waves, and so on. In this case, the rock gives a low radioactivity reading, which suggests that it is sand; its resistivity is high, which suggests it is oil-bearing. This is wizardry that few firms can match. And probably none is a regular oil company.
Oilfield services (OFS) firms such as Schlumberger are the unsung workhorses of the oil industry. They do most of the heavy lifting involved in finding and extracting oil and gas. They are far less well-known than the oil firms that hire them, but immensely lucrative. Schlumberger, with headquarters in Paris and Houston, earned profits of $5 billion on revenues of $40 billion last year. Its market capitalisation has risen fourfold in the past decade, to $91 billion. That is bigger than several international oil companies, including ENI ($82 billion), Statoil ($75 billion) and Conoco-Philips ($71 billion).
Schlumberger’s success highlights a shift in the balance of power between oil companies and their flunkeys. Until the 1990s OFS companies were far smaller and earned low margins on straightforward tasks, such as drilling vertical wells. That has changed dramatically.
With the price of oil so high, firms are scrambling to pump it out of ever more remote and costly crevices. Over the past decade the oil industry’s annual spending on exploration and production has increased fourfold in nominal terms, while oil production is up by only 12%. The big services companies, which invest heavily in technology (see chart), have been growing by around 10% a year. According to McKinsey, a consultancy, OFS companies grossed around $750 billion last year.
OFS firms come in three flavours. Some make and sell expensive kit for use on drilling rigs or the seabed. These include FMC, Cameron and National Oilwell Varco, all $10-billion-plus companies. Some own and lease out drill-rigs. These companies include Transocean, Seadrill, Noble and Rowan. The third group carries out most of the tasks involved in finding and extracting oil. It is dominated by four giants: Schlumberger, Halliburton, Baker Hughes, and Weatherford International.
Most of these firms were relatively small until the 1980s, when several oil companies decided that humdrum drilling chores were no longer worth doing in-house. Oil was easy then. Drilling yielded low margins that did not justify its claim on capital, so the oil majors outsourced it. This gave OFS firms space to grow.
They grew even faster in the early 1990s, when a tightening oil market drove demand for new technology. This led to breakthroughs in 3D seismology and directional drilling. These breakthroughs allow oil to be sucked economically from far beneath the ocean floor, and out of depleted and formerly abandoned wells.
But such inventions do not come cheap. Schlumberger invests roughly $1 billion a year in research and development, a level it maintained even during the slump after the 2008 financial crisis. That is as much as the mighty ExxonMobil spends; as a share of sales, five times more. The big OFS companies now probably file more patent applications than the oil majors, whose technological skills are largely interpretive. (For example, an oil major may decide where and how to drill based on geophysical data provided by an OFS firm.)
The oil business is likely to grow even more dependent on brainy OFS firms. Global production from mature oilfields is falling by between 2% and 6% a year. In the North Sea it has declined by 6% a year on average since 1999. With global demand for oil growing by 1-2% a year, there are persistent fears of a supply shock. Hence the current high oil prices: even after a 20% fall in recent months, Brent Crude is now around $100 a barrel. Oil firms are searching harder in more remote places, such as the Arctic and the deep seas off Brazil. Operating in such places will require yet more snazzy technology.
With hindsight, the oil companies’ decision to outsource the grubby bits of the job looks like an opportunity squandered. It has also left the oil firms hostage to the availability of increasingly expensive and sought-after services, from advanced drilling to deepwater rigs, which a dwindling number of OFS firms can provide.
There is, at present, still a fair amount of competition in most parts of the services industry. Each big OFS firm has different strengths, and plenty of smaller ones occupy specialised niches. Yet in some areas, especially the geographically remote ones, the demand for complex services often outstrips the supply.
Even worse for the likes of Exxon and BP, this has come at a time when state-owned oil firms have been muscling onto the stage. In the past couple of decades these national oil companies have claimed the best acreage in most old oilfields. The OFS firms have helped them to do so. Where once the state-owned giants hired oil majors to do the work, now they can manage projects themselves and hire technical help directly from the services firms. This can sometimes involve a limited sharing of risk between national and OFS firms, just as in a regular joint venture between oil companies.
Schlumberger, for example, will agree to a measure of payment-for-performance in big contracts. If it can drill more oil from a well than the contract says it must, it charges a higher fee. Other services firms have gone further, taking small equity stakes in exploration projects.
Some analysts wonder how all this might hurt the oil majors. A few decades ago national oil companies had to turn to oil majors for the technology required to get the stuff out of the ground. Today, oilfield service companies offer all the necessary technology and are increasingly willing to take on some of the same risks as an oil company, notes Marcel Brinkman of McKinsey.
Still, it would be wildly premature to bid Exxon adieu. Schlumberger’s performance-based contracts are a long way short of owning reserves—something the company says it will never do. It lacks the mammoth balance-sheet that oil firms maintain to manage the huge risks in oil exploration. It also lacks Exxon’s expertise in managing huge projects. And it is reluctant to annoy its customers by competing with them. Moreover, choosing where and how to explore (another strength of the oil majors) is trickier than you might think.
Instead, Schlumberger is planning more of what it is best at: pushing the technological boundaries of extracting the black stuff. It has recently been busy making acquisitions—including of Smith International, an American drill-bit company, for $11.3 billion—which have given it know-how in most segments of exploration and production. It now hopes to re-engineer the entire process.
The prize of increased efficiencies—delivered in barrels of money, not oil—could be vast. A big deepwater drilling rig costs half a million dollars a day to rent, and can take three months to drill a complicated well. Any OFS company that can shave a few days off that time will be in the money. Drilling is thrilling, and getting more so.

Why Natural Gas

Why Natural Gas – CococoPhillips

Air Land Water
Natural gas is a cleaner-burning fuel with additional environmental benefits over other energy sources when used for electricity and heat production.
Cleaner Burning
Burning natural gas results in very low emissions of nitrogen oxides and sulfur dioxide – reducing acid rain and smog – and virtually no emissions of mercury or particulates (soot), making it among the cleanest ways to generate electricity. Accounting for emissions from fuel production through transportation and conversion, efficient natural gas power plants produce half the carbon dioxide emissions of coal-fired plants.
The modern fleet of U.S. natural gas-fired generating plants operates at just 42 percent of capacity. Utilizing these plants to displace coal-fired power generation is the fastest and most economical path to significant carbon emission reductions. Building and operating new efficient natural gas power plants to replace coal, while reducing carbon dioxide emissions, costs about 40 percent less than new wind generation. Producing electricity from natural gas is highly efficient and requires smaller, less costly pieces of equipment. Also, natural gas does not require the capital equipment and operating costs to reduce air emissions, or the need to dispose of solid waste, that coal-fired plants do.
Other Environmental Benefits
In addition to reduced air emissions, natural gas has other environmental benefits that make it a smart fuel choice. For instance, natural gas-fired power plants use about 60 percent less water than coal plants and 75 percent less water than nuclear power plants for the same electricity output. In addition, natural gas-fired power plants require the least amount of land per megawatt of capacity versus other new power generation options. Wind and solar require 20 times more land to power the same number of homes as a natural gas-fired power plant.
Natural gas for power production avoids some of the challenges facing wind, solar, biofuels and nuclear power generation technologies, such as visual impact, competing land uses, bird strikes and waste disposal. No other electricity generation source can respond as rapidly to fluctuations in U.S. consumer electricity demand as natural gas. Another benefit is that natural gas-fired generation reliably backs up wind- and solar-generated electricity when the wind doesn’t blow and the sun doesn’t shine.
Natural gas is the fastest and most economical path to significantly reducing U.S. emissions of carbon dioxide from power generation, while minimizing our impact on the land and use of our water resources. The many environmental benefits in accelerating the use of natural gas is another reason why we believe natural gas should be an important part of America’s energy future.

Natural Gas Drilling & Completion

Conoco Phillips
Natural Gas Drilling & Completion
Natural gas is found throughout the world in underground formations, such as sandstone, carbonates, coal and shale. Gaining access to the gas involves drilling vertical, horizontal or multi-lateral wells to the target formation. Various completion techniques, such as hydraulic fracturing, are then used to create an effective connection between the well and the targeted hydrocarbon-containing formation, thereby providing a pathway for the gas to be produced.
Before drilling a well, our geologists and engineers complete a full analysis of the geology using proprietary and public data. They assess results from other wells drilled in the vicinity, including water wells, producing oil and gas wells and nonproducing wells (dry wells). A plan is developed for drilling and completing the well that must be approved by state regulators. The company proactively engages key stakeholders, including communities, officials, government agencies and regulators, as plans are being developed.
Many of the steps described are common to all oil and gas well planning and operation efforts, regardless of well design or the formation being targeted for development.
Once a target formation has been identified and appropriate land leases acquired, environmental and regulatory reviews are conducted to assess related environmental impacts. Social and local issues are addressed, and stakeholder engagement commences. The permitting process then begins as prescribed by federal, state and local regulatory requirements.
Before drilling begins ConocoPhillips engineers, geoscientists and environmental employees work with regulatory staffs to collect and analyze information on the geology and surface conditions of the potential drill site. Drilling, surface use and water management plans are developed to maximize natural gas production while protecting the environment and minimizing the well’s overall footprint.
Following the construction of a well pad, a large hole is drilled to a shallow depth. A relatively short length (typically 40 to 120 feet) of large-diameter steel pipe (conductor casing) is set to stabilize the ground at the top of the well.
Drilling continues to a pre-determined depth below the base of usable water. This depth is specified by state or federal regulators for the purpose of protecting potential usable groundwater resources and is based on local geology. While drilling this section, drilling mud – a mixture of fresh water and clay – is pumped into the hole to cool the drill bit, remove any cuttings and create a boundary between the well and surrounding rock.
The drill pipe and drillbit are removed, and a steel casing is inserted. Cement is pumped through the casing, filling the annular space between the outside of the casing and the wellbore. This creates a sealed container that extends from the surface to below the base of freshwater zones. The blowout preventer is then installed at the surface.
Following a series of tests, drilling resumes until it reaches the kick-off point – when a specialized motor is added to the drilling assembly that allows the curved and horizontal sections of the well to be drilled. The kick-off point is typically thousands of feet below any freshwater zones
Once the target depth is reached (based on the length of the horizontal section required), the drilling assembly is removed, and the steel casing is inserted through the entire length of the well. More cement is pumped through the casing, creating another cement-reinforced layer of protection.
Next, a specified length of horizontal casing is perforated to provide a way for natural gas to enter the production casing.
A fluid consisting of water, sand and a small amount of chemicals – some of which can be found in common household and food products – is then injected through the perforations to stimulate gas recovery. The fluid penetrates the shale and creates cracks, or fractures, in the rock. The sand or ceramic particles, called proppant, are carried by the fluid and deposited in the narrow fractures, creating a pathway for gas to reach the well.  This step is called hydraulic fracturing.
A plug is set inside the casing to isolate the stimulated section of the well. The entire perforate-inject-plug cycle is then repeated at regular intervals along the horizontal section of the well. Finally, the plugs are drilled out, allowing the gas and fluids to flow into the wellbore and then up to the surface inside the casing or tubing.
The gas/fluid mixture is separated at the surface, and the fracturing fluid (also known as flowback water) is captured in steel tanks or lined pits. The fracturing fluids are then disposed of via government-approved methods.
The entire well construction process generally takes only two to three months, compared to the 20- to 30-year productive life of a typical well.

US Gas Rigs Drop

U.S. Gas Rigs Drop First Time in Three Weeks, Baker Hughes Says
By Lynn Doan – Apr 26, 2013
The number of gas rigs in the U.S. fell for the first time in three weeks, declining by 13 to 366, according to Baker Hughes Inc. (BHI)

Oil rigs increased by 10 to 1,381, data posted on Baker Hughes’ website show. Total energy rigs slipped by four to 1,754, the Houston-based field-services company said.

The U.S. gas rig count has dropped to less than a fourth of its peak of 1,606 in 2008 as energy producers abandoned natural- gas plays to drill for more lucrative crude and natural-gas liquids. The boom in tight-oil production helped the U.S. meet 84 percent of its energy needs last year, the most since 1991, according to the U.S. Energy Information Administration, the Energy Department’s statistical unit.

ConocoPhillips (COP), the largest independent U.S. oil and natural gas producer, has no plans to start “redirecting any capital toward gas assets until it’s significantly north of current prices,” Matthew Fox, an executive vice president at the Houston-based company, said in a conference call with investors yesterday.

The company’s fuel production in Texas’ Eagle Ford shale formation is about 60 percent oil, 20 percent natural gas liquids and 20 percent dry gas, Jeff Sheets, Conoco’s chief financial officer, said during the call. Its wells in North Dakota’s Bakken formation produce mostly oil, he said.

Gas Stockpiles

U.S. gas stockpiles increased by 30 billion cubic feet to 1.734 trillion in the week ended April 19, the EIA said yesterday. Supplies were 31.8 percent below a year earlier and 5.1 percent below the five-year average, down from a deficit of 4.2 percent the previous week.

Natural gas for May delivery fell 5.6 cents, or 1.3 percent, to $4.111 per million British thermal units on the New York Mercantile Exchange at 1:11 p.m. Futures have more than doubled in the past year and have been trading above $4 for three straight weeks.

Exxon Mobil Corp. (XOM) remains focused on liquids-rich drilling and has “the flexibility and optionality” to ramp up gas output should prices keep rising, David Rosenthal, vice president of investor relations for the Irving, Texas-based company, said in a conference call with investors yesterday.

“We don’t tend to take the last two data points and draw a trend line and react in that manner,” he said. “We tend to have longer-term approaches to the development of all of our resources.”

U.S. oil output reached 7.33 million barrels a day last week, a two-decade high, EIA data show. Stockpiles climbed to 388.6 million, near a 22-year high.

Crude for June delivery on the Nymex fell 66 cents, or 0.7 percent, to $92.98 a barrel. Prices have decreased 11 percent in the past year.

To contact the reporter on this story: Lynn Doan in San Francisco at

To contact the editor responsible for this story: Dan Stets at


Shale Gas Boom: ConocoPhillips, An Underrated LNG Player?

Fri, Apr 26 2013, 10:12 | by Stephan Dube
about: COP
This article is presenting one of the major energy company in the U.S. and how the natural gas boom of the last few years have changed its producing strategy (see the article here). After a brief presentation, we will look at some of its current operations worldwide, focusing on its natural gas and LNG (liquefied natural gas) plays. The last part will discuss about some of its major natural gas projects under way, the financial highlights of the company including its Q1 2013 highlights, as well as its future outlook, in a second article. Let’s get started with the first part in this article beginning with the company’s presentation.

The third-largest energy company in the U.S.

Headquartered in Houston, Texas, ConocoPhillips (COP) has operations in almost 30 countries. Key focus areas include operating producing assets, developing its major projects and exploring for new resources in promising areas. The portfolio includes legacy assets in North America including its growing shale and oil sands businesses, Europe, Asia and Australia.

(Click to enlarge)

Source: ConocoPhillips

Furthermore, the company is developing few major international projects and a global exploration program. The company’s production streams include light oil, heavy oil, oil sands, NGL (natural gas liquids), conventional natural gas, coalbed methane, shale gas and oil and LNG.

ConocoPhillips traces its beginnings to 1875, when Conoco founder Isaac E. Blake envisioned an idea to make kerosene available and affordable to townspeople in Ogden, Utah. Thirty years later, the foundation for Phillips Petroleum Company began when brothers Frank and L.E. Phillips hit the first of 81 wells without a dry hole. Nearly a century later, the two companies combined their strengths to form what is now the third-largest energy company in the U.S. The ConocoPhillips merger, completed during August 2002, paved the path for the company’s current and future success.

In 2006, Burlington Resources joined ConocoPhillips. The acquisition brought Burlington’s more than 100 years of experience to ConocoPhillips and enhanced the company’s position as a leading producer and marketer of natural gas.

Best Natural Gas Worldwide Assets

Source: ConocoPhillips 2012 Annual Report


Prudhoe Bay

Source: ConocoPhillips

Prudhoe Bay also is the site of one of the largest waterflood and enhanced oil recovery projects in the world, as well as a large natural gas processing plant that processes more than 6.75Bcf/d (billion cubic feet per day) of natural gas that is reinjected into the reservoir. Prudhoe Bay also contains natural gas, and ConocoPhillips continues to work on opportunities to develop and monetize that resource.

North Cook Inlet

Source: ConocoPhillips

Owned and operated by COP at 100%, the field was discovered in the northern waters of Cook Inlet in 1962 and is produced from the Tyonek Platform which began operation in 1968. While natural gas production averaged nearly 34Mmcf/d (million cubic feet per day) in 2011, the company managed to increase its production for 2012 with 49Mmcf/d.

Beluga River

Source: Alaska Oil and Gas Conservation Commission

Part of the Cook Inlet Area, the Beluga River natural gas field serves major customers in south-central Alaska, including local utilities and industrial consumers. Beluga River is owned at 33.3% and operated by COP with co-venturers Hilcorp at 33.3% and Municipal Light and Power with 33.3%. Total production for 2012 averaged 55Mmcf/d.

Trans Alaska Pipeline System

Source: MATCOR

The 800-mile Trans Alaska Pipeline System is a joint-venture operated by Alyeska Pipeline Service Co. The co-venturers are BP (BP) at 46.9%, ConocoPhillips at 28.3%, ExxonMobil (XOM) with 20.3%, Koch Alaska Pipeline Co. with 3.1% and Chevron (CVX) at 1.4%. The pipeline transports North Slope oil to the tanker terminal in the ice-free port of Valdez, Alaska. The pipeline carries approximately 600Mbd (thousand barrels per day) of crude oil and NGL.

Continental U.S.

Eagle Ford

(Click to enlarge)

Source: ConocoPhillips

The liquids-rich Eagle Ford shale trend in South Texas represents one of ConocoPhillips’ most promising opportunities. With approximately 223,000 net leasehold acres in the area, the company accelerated its delineation activities during 2011. For 2012, production increased by 144% over 2011, with an average of 85Mboe/d (million barrels of oil equivalent) and a peak production of 103Mboe/d while running 11 operated drilling rigs.

Fort Worth Basin

(Click to enlarge)

Source: ConocoPhillips

With a significant working interest in about 147,000 net acres in north-central Texas, ConocoPhillips is able to strongly influence the pace of development in this basin. The company added 24 new wells in 2012. For 2012, production has averaged 49Mboe/d. The basin includes the liquids-rich North Barnett Trend.

Permian Basin

(Click to enlarge)

Source: ConocoPhillips

The Permian Basin in West Texas and southeastern New Mexico is a prime example of increasing existing company resources from legacy assets. COP continues to effectively optimize production from its 1.1-million-net-acre lease position. The company drilled 103 wells in 2011 and increased drilling activity in 2012, resulting in a production of an average of 111Mmcf/d. With resources of approximately 1Bboe (billion barrels of oil equivalent), the basin is expected to remain a high-liquids-production asset for years to come.

San Juan Basin

(Click to enlarge)

Source: ConocoPhillips

ConocoPhillips is the largest operator in the San Juan Basin, located in northwestern New Mexico and southwestern Colorado. The company has a significant number of productive leaseholds and mineral acreage in this area. To offset the natural decline rate, the company has an ongoing program of drilling new wells, performing workovers on existing wells, adding compression and installing artificial lift when economic to do so.

In 2011, net production from the Fruitland Coal Formation averaged 296Mmcf/d of natural gas and 3Mb/d of liquids. The Mesa Verde Formation, which consists of the Lewis Shale, Cliffhouse, Menefee and Point Lookout sands, is the largest producing tight-gas formation in the San Juan Basin. Net production from the conventional tight-gas producing formations averaged 477Mmcf/d of natural gas and 46Mbd of liquids in 2011. For 2012, San Juan produced in all, 750Mmcf/d of natural gas and 49Mb/d of liquids.

Texas and Oklahoma Panhandles

(Click to enlarge)

Source: ConocoPhillips

The company holds approximately 1.1 million net acres of development and exploration assets in this region. Producing wells are primarily shallow gas wells in the panhandles of Texas and Oklahoma.

Anadarko Basin

Located primarily in western Oklahoma, Anadarko encompasses 250,000 net acres and contains producing formations ranging in depth from 11,000 feet to more than 21,000 feet. ConocoPhillips has over 140,000 net acres in the Granite Wash Play in the Anadarko Basin. The industry has transitioned its development focus from vertical to horizontal wells, targeting the most prolific liquids-rich intervals. For 2012, Anadarko produced an average of 124Mmcf/d.

Wind River Basin

The Wind River Basin operations cover more than 1.1 million net acres in Wyoming with natural gas operations from multiple horizons ranging in depth from 5,000 feet to more than 25,000 feet, where the deep Madison Formation occurs. The company owns an approximate 46% working interest in the Lost Cabin Gas Plant and net revenue interests varying from 22% to 40% in the producing reservoirs. Wind River produced for 2012, an average of 78Mmcf/d.

Total production for the U.S excluding Alaska averaged 1,493Mmcf/d of natural gas in 2012.

Freeport LNG Terminal

(Click to enlarge)

Source: gCaptain

ConocoPhillips has a long-term agreement with Freeport LNG Development, L.P. to utilize 0.9Bcf/d of regasification capacity at Freeport’s 1.5Bcf/d LNG receiving terminal in Quintana, Texas. The terminal became operational in 2008. In order to deliver natural gas from the Freeport Terminal to market, ConocoPhillips constructed a 32-mile, 42-inch pipeline from the terminal to a point near Iowa Colony, Texas. For more information on Freeport LNG, one of my article discuss about the top promising LNG investments here.

Golden Pass LNG Terminal

Source: Natural Gas Daily

ConocoPhillips has a 12.4% ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass Pipeline. It is located adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal became commercially operational in May 2011. ConocoPhillips will hold terminal and pipeline capacity for the receipt, storage and re-gasification of LNG purchased from Qatargas 3 and the transportation of re-gasified LNG to major interstate and intrastate natural gas pipelines.

Phoenix Park Gas Processors Limited

Source: The Trinidad Guardian

ConocoPhillips owns a 39% interest in Phoenix Park Gas Processors Limited which processes natural gas in Trinidad and markets NGL in the Caribbean, Central America and the U.S. Gulf Coast. Its facilities include a 2Bcf/d gas processing plant and a 70Mb/d NGL fractionator. In 2011, ConocoPhillips’ share of NGL extracted from this facility averaged 8Mb/d, while the company’s share of fractionated liquids averaged 16Mb/d.

Wingate Fractionator

The Wingate Fractionator, located in Gallup, N.M., is 100% owned and operated by ConocoPhillips and has an inlet capacity of 25Mb/d.

Western Canada

(Click to enlarge)

Source: ConocoPhillips

ConocoPhillips is one of the top three natural gas producers in Canada. Its operations are located primarily in Alberta and British Columbia, with some production in Saskatchewan. The company has an ownership position in 80 natural gas processing plants in the region. The company holds leasehold rights in 8.8 million gross acres (6.1 million net acres) in western Canada.

Canada’s Oil Sands

Source: ConocoPhillips

ConocoPhillips holds approximately 1 million net acres of land in the Athabasca Region of northeastern Alberta. The significant bitumen deposits on these lands are estimated to contain more than 15 billion net barrels of resources, making ConocoPhillips the holder of one of the largest land and resource positions in the region.

ConocoPhillips’ bitumen resources in Canada are produced via SAGD technology. SAGD involves injection of steam into the reservoir, effectively liquefying the heavy bitumen, which then is recovered and pumped to the surface for further processing.

COP’s net bitumen production from the FCCL Partnership (50% COP) and Surmont SAGD operations has grown by an average of 23% over the past three years to 67Mb/d in 2011, second among SAGD producers in Canada. The company has a number of ongoing development projects and further opportunities in these assets.

Net bitumen production is targeted to double by 2016, with a further doubling from 2016 to 2020, achieving a 17% compounded annual growth rate over the next 10 years. Additional opportunities in its portfolio have COP well-positioned to continue as a leading SAGD producer in Canada in the future. Total daily net production from COP in Canada averaged 928Mmcf/d in 2011, a decrease over 857Mmcf/d from last year.


(Click to enlarge)

Source: ConocoPhillips

Britannia, U.K.

Source: ConocoPhillips

Britannia is one of the largest natural gas and condensate fields in the North Sea. This joint-venture is operated by Britannia Operator Limited and is owned by ConocoPhillips at 58.7%, Chevron with 32.3% and BP with 9.0%.

Commercial production began in 1998. Condensate is delivered through the Forties Pipeline to the oil stabilization and processing plant, Kerse of Kinneil, near the Grangemouth Refinery in Scotland, and natural gas is transported through a dedicated Britannia pipeline to the Scottish Area Gas Evacuation (SAGE) facility at St. Fergus, Scotland. Britannia’s daily net production averaged in 2012, 117Mmcf/d of natural gas. Total daily net production from COP in U.K. averaged 463Mmcf/d in 2011 over 356Mmcf/d produced in 2012.


(Click to enlarge)

Source: ConocoPhillips

ConocoPhillips has had a presence in Indonesia for more than 40 years, operating six PSCs (production-sharing contracts). Three of the blocks are located offshore: the South Natuna Sea Block B PSC, the Kuma PSC and the Arafura Sea PSC. The three onshore PSCs are the Corridor Block PSC and the South Jambi ‘B’ PSC, both in South Sumatra, as well as the Warim PSC in Papua. Total daily net production from COP in Indonesia averaged 437Mmcf/d last year, a little decrease over 2011 with an average of 450Mmcf/d of natural gas produced.


Source: ConocoPhillips

In 2003, ConocoPhillips and Qatar Petroleum signed a Heads of Agreement to develop Qatargas 3, a large-scale LNG project in Ras Laffan Industrial City, Qatar. The integrated project comprises upstream natural gas production facilities to produce approximately 1.4Bcf/d of natural gas over the 25-year life of the project, as well as an initial average of about 70Mb/d of LNG and condensate combined from Qatar’s North Field.

(Click to enlarge)

Source: ConocoPhillips

The project also includes a 7.8Mtpa (million tonnes per annum) LNG facility. The first LNG cargo was loaded in November 2010, and the Qatargas 3 Plant is now fully operational. The LNG is exported in carriers owned by Qatargas Transport Co. and time chartered to Qatargas 3. Peak production was achieved in 2011 and is expected to continue for the life of the project. Total daily net production from COP in Qatar for 2012 averaged 367Mmcf/d compared to 2011 with an average of 370Mmcf/d of produced gas.

This concludes the presentation of ConocoPhillips’ current major assets worldwide in the natural gas play. Several other assets such as its plays in Norway, Malaysia, Australia or Nigeria could have been talked about. However, I tried to present the most prominent ones to give the investors a better idea of this company’s involvement in natural gas play.

The last part will discuss about some of its major natural gas projects under way, the financial highlights of the company including Q1 2013 highlights, as well as its future outlook in a forthcoming article. Will ConocoPhillips will profit from the natural gas boom of recent years? Does the company represents a good investment by taking into consideration its current plays in the commodity? These are the questions I will try to answer.

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

Energy Security

Oil and Gas: The Key to America’s Energy Security

The domestic oil and natural gas industry supports 9.2 million American jobs and 7.7 percent of the U.S. economy, while producing 51 percent of all the oil and petroleum products Americans consume. Every day, the industry fills state and federal government coffers with more than $86 million in taxes, fees and royalties. All while investing more than $2 trillion in U.S. capital projects to advance all forms of energy, including alternatives. There is no question—a thriving domestic oil and gas industry is vital to America’s energy and economic security.

And did you know that, with the right policies in place, the industry can contribute even more? In fact, U.S. and Canadian supplies can provide 100 percent of our liquid fuel needs by 2030 with the implementation of two straightforward policies—(1) accessing U.S. oil and natural gas reserves that are currently off-limits; and (2) partnering with our friendly neighbor to the north, Canada, in the development of the Keystone XL pipeline.

A recent study found that U.S. State Department approval of the pipeline expansion could bring an extra 830,000 barrels of oil per day—equal to about half of what is currently imported from the Persian Gulf. Canada has long been a vital partner in delivering American energy security. It currently supplies 25 percent of U.S. oil imports—more than any other country in the world.

In addition to powering America with reliable supplies of energy, in 2010 alone, the industry delivered benefits to the U.S. economy roughly equivalent to 60 percent of the government’s 2009 stimulus package—$476 billion in industry benefits, compared to $787 billion in planned government stimulus expenditures.

$266 billion in new U.S. capital project investment, $176 billion in wages and $35 billion in 2010 dividends also spur growth in manufacturing, transportation, technology, accounting services and in the larger U.S. economy.

The oil and gas industry also contributes to retirement security for millions of Americans. A 2011 Sonecon study found that, on average, oil and gas stocks comprise 4.6 percent of state pension fund assets, yet provide 15.7 percent of the returns—a ratio of 3.4 to 1.

Oil Production

Oil Production

When discussing oil industry production, consider this: geologists have estimated that the migration of petroleum from their place of origin deep inside the earth into surrounding reservoir rocks takes a long time. Time is measured in millions of years, not centuries!
They argue that this fact is based on the physics of fluid flow through semi-permeable material (rock) under a pressure gradient. The fluid must travel from pore to pore, micrometer by micrometer until settling in its host reservoir – and that simply takes time.

If no trapping mechanism exists, then the hydrocarbon rises to the top of the fluid column and/or surface where it seeps out. Although seeps are plentiful, their natural flowrates are not enough to meet demand.

Society, today, needs lots of oil – and, right now! Oil industry production must continually be produced in the millions of barrels per day to quench our thirst (view top oil company production rankings) . So, how do oil companies produce oil to satisfy this need?

They explore, drill wells, and produce oil at the field’s maximum efficient rate.

In places where a oil trap exists (see discussion about oil traps) , prior to well penetration, little if any fluid movement occurs, as the trapping mechanism prevents any escape of hydrocarbon within the structure. An equilibrium condition is established, balancing fluid phases and reservoir pressures – that is, until a well is drilled.

Imagine for a moment that the oil reservoir, located a mile or so beneath the earth’s surface, is like a giant sponge sitting on a kitchen counter. Oil saturates the reservoir like water saturates the sponge, filling most of the available pore spaces.

Just like a sponge sitting on a counter, the oil sits in suspension within the reservoir with no droplets escaping. Only when pressure is applied to the sponge by squeezing it or placing something on it, will the sponge give up some of its water.

Similarly, oil will not move until its equilibrium condition is upset. Once a well penetrates this isolated environment, releasing stored pressure, the well balance suddenly shifts and its characteristics will never again be the same.

So, how is oil produced?

Oil is produced through the creation of a significant pressure drop between the outer reaches of the reservoir and the wellbore at depth.

With pressure drops sufficient to overcome pore pressures, oil stored deep in reservoirs will flow to the low-pressure sink.

Getting oil to move out of the ground and to the market is what oil industry production and the petroleum business is all about. The challenge for the production engineer then is to first get the oil to the wellbore. The next challenge is to get it to the surface.

With the drilling of a well, subsurface pressures can be released. These pressures can and do exceed thousands of pounds per square inch (psi). When producing without artificial support, the reservoir pressure automatically begins to decline.

It is estimated in most producing wells, half of the total reservoir pressure drop occurs within the first 10-20 feet from the wellbore.

Now, having a means of escape, the enormous weight of the rock sitting atop of the reservoir squeezing the once resistant pores (see discussion on oil location) , now forces the pores to compress, expelling oil, gas and water through the well. The characteristics of the oil itself contain entrained lighter hydrocarbons (gases), which in the presence of a drop in pressure, begin to separate from heavier liquids and cause hydrocarbon to exit the reservoir. Water inflow, fed from external sources, constantly pushes against the hydrocarbons, which now can escape through the well.

These characteristics of a reservoir are known as natural drive mechanisms and are individually called compaction drive, solution gas/gas cap drive, and water drive. Reservoirs typically have components of several, if not all of the drive mechanisms at work, but usually have one of them behaving in a more dominant fashion than the others.

Understanding the particular drive mechanisms at work within a specific reservoir is essential to efficient and effective petroleum extraction. A company can easily drill and produce wells in locations that hamper natural drive mechanisms, leaving oil behind that will never be recovered.

The rate of flow of the fluids in the reservoir is governed by the fluid densities and the drop in pressure from the reservoir to the wellbore. Henry Darci, a nineteenth century engineer, was first to document the proportional relationship of flow rate and pressure drop in porous media.

As fluid is produced from a well under natural drive mechanisms, the pressure drop from the well, which was highest when the well was first produced, begins to diminish. As a consequence, the flow rate of the well, normally measured in terms of barrels per day, also diminishes. Without any assistance from the engineer, the well’s production will eventually slow to a trickle, and finally cease. This could take days, years, or decades to occur.

In some cases, the natural drive mechanisms currently aren’t or never were sufficient to produce oil at the surface. But, just because the oil can’t flow to the surface doesn’t mean it is not sufficient in size or quality for commercial production.

It is estimated that primary drive mechanisms can typically produce about 30% of the oil in place within a reservoir. That means seventy percent of the original oil remains in place!

Once the oil is in the wellbore, pumps are used as necessary to lift oil to the surface. Oil, gas and water enter the well through perforations placed in the cemented pipe at the reservoir depth.

Typically, a ball and seat pump is attached to a series of slender metal rods called “sucker rod” that is ultimately connected to a pumping unit sitting on the surface, adjacent to the wellhead. As the pumping unit head bobs up and down each time, the pump completes a stroke, lifting a column of fluid closer to the surface. Once at the surface, the reservoir fluids are piped to production facilities.

Supplementary production techniques (also called secondary and tertiary recovery) like waterflooding and gas injection serve to replenish reservoir pressures, driving oil towards the wellbore. Steam injection and in situ combustion techniques are generally designed to improve the viscosity of the oil (enhance its ability to flow). Miscible flooding, carbon dioxide flooding, and surfactant flooding focus on improving oil’s relative permeability to water and increase recovery.

Supplementary production techniques can add approximately 30% recovery of the original oil in place.

Production Monitoring/Forecasting

Current production rates are often compared with historical records and reservoir data to project future production trends and to assist in characterizing well performance. Production forecasts are vital to estimating the producible life of a well and its potential economic profitability.

How’s it done, you might ask?

Well, engineers have derived functions that describe and match a given well’s declining production history. This function can be extended to predict future well performance.

If a well deviates considerably from the history matched projection, it could suggest a change in the condition of the reservoir, well, well equipment, or operations and measurement devices (i.e. surface or subsurface deviations).

Various staff and/or resources can then be employed to investigate the situation. Remedial work can be scheduled to fix the identified problem (such as tubing leaks, water breakthrough, rod spacing, pumping unit imbalance, pump malfunctions, scale development, broken flowmeter impeler, test station malfunction, etc.). Service companies are hired to conduct a variety of tasks like oil well stimulation by injecting acid into wells to dissolve downhole obstructions, and rod, pumps and tubing retrievals.

Oil Well Stimulation

Oil Well Stimulation

Oil well stimulation plays a vital role in production operations. With oil prices at all-time highs, it is imperative from an oil company’s perspective and the consumer’s perspective that as much production as possible be safely extracted from the reservior.
Why? So, the oil company can realize the highest price per barrel, and the consumer can get more oil circulating in supply to balance demand. But then, we digress…

It has been said by many wise petroleum investors (oxymoron?) that the industry’s saving grace is that their assets are in the ground! Once found, they argue, it is difficult to lose. Clearly, these investors weren’t reservoir engineers as will be explained below.

Producing that oil isn’t as simple as running the kitchen faucet and watching the basin fill-up (see oil production discussion) . Natural production tendencies for wells are for the oil production rates (and reservoir pressure) to be at its highest at initial production, and fall-off considerably as the well is produced. Typically, one finds oil rates declining as water production increases, driving up operations costs while revenue shrinks. This scenario continues until the well fails and/or becomes uneconomic to operate or repair.

Oil Well Stimulation

Oil well stimulation plays a vital role in production operations. With oil prices at all-time highs, it is imperative from an oil company’s perspective and the consumer’s perspective that as much production as possible be safely extracted from the reservior.
Why? So, the oil company can realize the highest price per barrel, and the consumer can get more oil circulating in supply to balance demand. But then, we digress…

It has been said by many wise petroleum investors (oxymoron?) that the industry’s saving grace is that their assets are in the ground! Once found, they argue, it is difficult to lose. Clearly, these investors weren’t reservoir engineers as will be explained below.

Producing that oil isn’t as simple as running the kitchen faucet and watching the basin fill-up (see oil production discussion) . Natural production tendencies for wells are for the oil production rates (and reservoir pressure) to be at its highest at initial production, and fall-off considerably as the well is produced. Typically, one finds oil rates declining as water production increases, driving up operations costs while revenue shrinks. This scenario continues until the well fails and/or becomes uneconomic to operate or repair.

The purpose of oil well stimulation, then, is to increase a well’s productivity by restoring oil production to original rates less normal decline, or to boost production above normal predictions.

So, what is oil well stimulation?

Oil well stimulation is the general term describing a variety of operations performed on a well to improve its productivity.

Stimulation operations can be focused solely on the wellbore or on the reservoir; it can be conducted on old wells and new wells alike; and it can be designed for remedial purposes or for enhanced production. Its main two types of operations are matrix acidization and hydraulic fracturing.

Matrix acidization involves the placement of acid within the wellbore at rates and pressures designed to attack an impediment to production without fracturing or damaging the reservoir (typically, hydrofluoric acid is used for sandstone/silica-based problems, and hydrochloric acid or acetic acid is used for limestone/carbonate-based problems). Most matrix stimulation operations target up to a ten foot radius in the reservoir surrounding the wellbore.

Hydraulic fracturing, which includes acid fracturing, involves the injection of a variety of fluids and other materials into the well at rates that actually cause the cracking or fracturing of the reservoir formation. The variety of materials includes, amongst others: water, acid, special polymer gels, and sand. The fracturing of the reservoir rock and the subsequent filling of the fractured voids with sand (“proppant”) or the creation of acid channels allows for an enhanced conduit to the wellbore from distances in excess of a hundred feet.

So, why do wells need oil well stimulation?

Hydraulic fracturing and acid fracturing in practically all types of formations and oil gravities, when done correctly, have been shown to increase well productivity above that projected in both new and old wells. From an economic standpoint, oil produced today is more valuable than oil produced in the future. Fracturing candidates may not necessarily “need” oil well stimulation, but the economics may show that such a treatment would pay=off.

To understand why remedial stimulation (matrix acidization) is necessary, you have to consider the conditions at work, deep down inside the reservoir…

Before the well is ever drilled, the untapped hydrocarbons sit in the uppermost portions of the reservoir (atop any present water) inside the tiny pore spaces, and in equilibrium at pressures and temperatures considerably different from surface conditions.

Once penetrated by a well, the original equilibrium condition (pressure, temperature, and chemistry) is permanently changed with the introduction of water or oil-based drilling fluids loaded with suspended clays, and the circulation of cement slurries. The interaction of the introduced fluids with those originally present within the reservoir, coupled with pressure and temperature changes can cause a variety of effects which, in turn, can plug the numerous odd-shaped pores causing formation damage. Some of the types of damage include: scale formation, clay swelling, fines migration, and organic deposition.

Petroleum engineers refer to the level of formation damage around the wellbore as skin effect. A numerical value is used to relate the level of formation damage. A positive skin factor reflects damage/impedance to normal well productivity, while a negative value reflects productivity enhancement.

Formation damage, however, is not limited to initial production operations. Remedial operations of all kinds from well killing to well stimulation itself, can cause formation damage. Nor is fines and scale generation limited to the reservoir. They can also develop in the wellbore in casing and tubulars, and be introduced from surface flowlines and incompatible injection fluids. These fines and precipitates can plug pores and pipe throughout an entire oil field.

In short, any operation throughout a well’s life can cause formation damage and impede productivity.

So, how do you keep from damaging the formation while stimulating a well?

Oil field service companies offer chemical inhibitors useful for the full spectrum of well operations that can be injected into the well ahead of acidization or other such stimulation activities to reduce fines generation and organic deposition, or introduced in surface flowlines on a regular basis to prevent scale precipitation and build-up.

Operational techniques such as bringing on production or injection slowly after stimulation activities (to prevent damaging flow surges which could mobilize once immobile fines within the pores, plug perforations, or cause sand control problems downhole or at the surface), and routine maintenance and surveillance (like cleaning out process filter traps which can easily clog lines and cause the transfer of damaging suspended particles, or monitoring production decline to identify potential deviances before the problem is exacerbated).

Importantly though, a sound understanding of formation damage causes, and the inclusion of chemists/chemical engineers on the production team will lead to increased well productivity and life. – The industry’s number one primer!
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