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 ldoan6@bloomberg.net

To contact the editor responsible for this story: Dan Stets at dstets@bloomberg.net

ConocoPhillips

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

Alaska

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.

Europe

(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.

Indonesia

(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.

Qatar

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.

http://seekingalpha.com/article/1375601-shale-gas-boom-conocophillips-an-underrated-lng-player

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.

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Oil Well Drilling

Oil Well Drilling

Oil well drilling has been the main means of producing oil ever since Colonel Drake drilled that first well in 1859, which signaled the start of the American petroleum industry.
Drilling techniques and equipment have changed throughout the decades from cable tools to rotary-based ones, from straight holes to sidetrack and GPS-based directional drilling, and from “guess-timates” and “feel” to computer-based accuracy.

The biggest improvement in oil well drilling, however, has been in the preparations prior to ever breaking ground.

The drilling of a well, especially a “wildcat” (see oil exploration discussion), is a milestone event, involving practically every sub-discipline of the oil business, and signifies the start of direct field investigation.

For the oil exploration and production company, the drilling of the well represents final exploration sunk costs prior to the possibility of recovering those costs through well production revenues. For the petroleum geologist and the reservoir engineer, the drilling of the well represents the final confirmation of the interpretation of numerous strands of indirect evidence of oil’s presence. For the production and facilities engineers, it represents the soon to be realized asset requiring sub-surface and surface management and equipment to maximize production (see oil production discussion). And, for the drilling engineer, well, it is time to earn their pay!

Through experience and communications with geologists, reservoir engineers, production engineers, and facilities engineers – the technical team – the drilling engineer develops a plan for reaching the targeted formation at the bottomhole location identified, from the surface location specified – at the cost authorized.

Before ever setting up on the drilling location, the drilling engineer has gained all of the necessary approvals to drill from company and regulatory authorities (click here for regulatory contact information). The appropriate hole dimensions, the wireline testing procedures, the well casing program, and the cement volumes are all known upfront (see well capacity tables).

The drilling engineer has already scheduled an oil well drilling rig, alerted a wireline and cementing service company, and ordered necessary drilling fluids, tanks, pipe and safety equipment (including blowout prevention equipment; Click here to view oil field service company contacts ).

Operations normally proceed on a 24 hours per day basis and depending on methods, depths, and rock types encountered, can last anywhere from a few days to several months.

History has shown that rarely do operations proceed in a “normal” fashion. Each well is its own story. It is quite normal to encounter hard rock zones, and experience sand control problems, as well as for minor equipment breakdowns to occur – right next to a well which didn’t experience half of the problems! Drill bits wear out, wrong auxiliary equipment is delivered, and various other events happen that slow progress, raise corporate anxieties, and compromise schedules.

Due to all of the problems, which can and do happen on site, oil companies have increasingly focused on safe operations. This is something everyone can control.

Most oil well drilling operations are actually completed by drilling service companies, with oil company drilling engineers supervising. Oil companies are using their natural leverage by insisting on safe operations by contractors, which minimize employee “accidents” and environmental impacts, and maximize accountability. Drilling service companies with poor safety records are not kept for long.

Drilling Operations

Operations proceed in accordance with terms of a permit issued by the regulatory agency with jurisdiction. Normally, a drilling location is graded, a conductor pipe is set to support subsequent casing strings, blowout control equipment is installed and tested for well safety, the drilling rig and auxiliary equipment is moved in and set up, and drilling operations are underway.

Contemporary drilling operations consist of downhole tools (drill bits, reamers, shock absorbers, etc.), drill string components (drill collars, drillpipe, kelly, etc.), suspension equipment (rotary swivel, hook, blocks, and wire rope), supporting structures (derrick), rotary drive mechanism (rotary table, turbodrill, dynadrill), hoisting equipment (drawworks, auxiliary brakes, cathead, etc.), transmission systems (mechanical transmission, clutch, belts, and chains), prime movers (diesel, turbo-electric), hydraulic circulating system (slush pump, high pressure surface equipment, drill string, shale shaker, desander, degasser, mud tanks/mixers), and rig floor and wellhead accessories/tools (cat lines, elevators, rotary slips, power slip, safety clamps, power tongs, rig instrumentation, blowout prevention equipment, etc.) (look at a picture of a drilling rig).

Although each area is vitally important to safe and efficient drilling operations, the drill string including the downhole tools is the most important area; being at the point of impact, transmitting surface derived energy into bottom-hole torque and hole digging.

The drill string/subsurface assembly is composed primarily of a swivel, a kelly, drillpipe, a drill collar, and a bit. The swivel connects the rotating drill string to the drilling rig support system. It suspends the drill string, permits free rotation and serves as the means for drilling fluid circulation. Drilling fluid is circulated through the drill pipe and bit to cool the bit and assist in cuttings removal. The drilling fluid also serves to coat the open-hole to prevent cave-ins and prevent any reservoir fluids (oil, gas and water) encountered from rushing in.

The swivel connects to the kelly, which is usually either a square or hexagonal-sided pipe of about 43 feet long, that transmits the torque from the rotary table on the rig floor to the drill string causing the bit to turn and make hole. Drill pipe sections are connected to the kelly one at a time allowing the bit to work deeper and deeper in the hole.

The drill collar is a heavy-walled pipe which connects the drill bit to the drillpipe. Its weight puts pressure on the bit to keep it working at the bottom of the hole.

The drill bit is the primary downhole tool, cutting up formation as it rotates. Diamond bits are used for hard formations. However, tri-coned steel-teethed bits are most commonly used today.

Sometimes, geologists inspect the cuttings that are circulated to surface to identify and confirm the formation that is currently being drilled.

At various and defined intervals, the well may be logged by wireline service companies. Why is this done? Well logging tells the industry experts the formations they are in, the fluids present within the formation (including oil!) and the quality of the cement job. In some drilling operations, wells are logged as they are being drilled using sophisticated tools which continuously transmit vital downhole information to surface without having to cease hole-making.

Metal pipe called surface casing is inserted into the well once the drillpipe is removed, and is cemented to the earth by cementing service companies. Cement is pumped and circulated within the well to permanently affix the pipe to the earth. This provides support, and limits communication between the surface and the subsurface to just that space inside of the pipe.

Subsequent drilling punctures the bottom of the recently placed cement sheath and continues down to the objective depth. To drill deeper, the rig crew performs the seemingly routine act of ceasing rotary table rotation and mud circulation, lifting the drill string, setting it on slips at the rig floor, breaking the joint between the kelly and the topmost drillpipe with tongs, screwing on an additional length of drillpipe at the kelly, lifting the string again, removing the slips, lowering the string downhole, and reestablishing mud circulation and rotary table rotation.

Intermediate casing might be run in hole and cemented, too, depending on well design criteria and formation characteristics. When the total depth is reached a final cement job is conducted to either plug the well back up because no significant hydrocarbon was found, or to secure the production casing string in place for future completion and production.

The drilling contractor rigs down and moves off of the drilling location and heads on to the next assignment.

Source Of Oil

Source of Oil

Well, silly, it comes from oil wells, of course! Sorry, that was just too easy to pass up (and in some respects the best answer out there)! Really now, where does oil come from?
The truth is, no one is completely certain how oil originated, migrated and accumulated.

Prevailing wisdom, based on over a hundred years of production history, has it that crude oil was formed from layers of dead organisms lying on the sea floor for millions of years. Over time, sand, clay, and limestone layers covered the rich organic sediments, which are typically fine-grained shales, choking out oxygen and allowing bacteria to break down the organisms.

As the organic-rich sediment was covered with more and more layers of earth, the weight of the overburden caused pressure and heat to transform the organic material into one of the various phases of hydrocarbon (natural gas, crude oil, or bitumen – see oil definition discussion). Scientists call this organic-rich sediment layer the source rock, as it is where oil is created.

It is estimated that it took millions of years to convert the organic matter into the quantities of hydrocarbon produced in the oil fields of today (see oil accumulation, and oil location discussions). As a result, oil is considered a finite resource. As the oil fields around the world are identified, and oil increasingly produced, the earth’s oil generating machine cannot keep pace, and the world’s overall oil balance declines.

Another novel theory for oil’s origin suggests that it is an inorganic product originating deep in the earth, between the mantle and the crust. Miles below the earth’s surface, it is theorized, the interaction of a now mobile, inorganic methane and high temperature pockets takes place and results in the condensing of crude oil.

An intriguing aspect of this theory is that oil is constantly being generated in numerous places around the world, and at rates that can continue to sustain our current way of life. So now, according to some, oil is not a limited resource after all.

It should be noted that this inorganic theory is held by a minority of industry professionals. The oil discoveries and development plans throughout the world have been based on the organic theory of hydrocarbon origination and a declining inventory. Seems to me like conventional wisdom wins the day.

So, where does crude oil come from? You decide and let me know!

Oil Exploration

Oil Exploration

It all begins with oil exploration…
Petroleum geologists and engineers have established that oil, when trapped, collects into underground pools called reservoirs. It is from these reservoirs that oil is produced. So, all these geologists have to do is find the oil reservoirs and sit back and watch the oil production flow! Couldn’t be easier right? Well, not exactly.

It is said that the best place to find oil is in an oilfield. This is true, without question. But, what do you do when there is no defined oilfield, and there are no nearby wells? It sounds quite simplistic but, think about it, every major oilfield must have begun with the drilling of the field’s first well.

How did they know where to drill the well, and how did they convince their bosses that drilling that well was worth the expensive research and drilling costs? Doesn’t sound so easy now, eh?

If you’re thinking there’s some risk to all of this, well there definitely is tremendous risk!

The industry calls these wells miles away from known production, wildcats. Depending on the results of their attempts at finding hydrocarbon, the wells are known as discovery wells or dry holes.

If the discovery well shows hydrocarbon, other development wells are drilled to confirm the find. If nothing is found, well, the operator will simply abandon the well and move on to other prospects and plays.

Through the utilization of a variety of high and low-tech tools and methodologies, today’s producing reservoirs were discovered.

The presence of oil seeps and pits at surface is a strong indication that oil may be present underground. If a trapping mechanism exists below, one may have found a reservoir.

The surface exposure (outcropping) of known source and reservoir rock suggests the right conditions for oil generation and storage may be present. If a trap of some kind were detected, it is possible that a reservoir could be discovered.

So, how do geologists detect reservoirs miles below the surface of the earth?

The only direct way of confirming oil’s presence is to drill a well.

But, drilling a well is an expensive proposition. Most wells cost in excess of $100,000 to drill, and many cost over $1,000,000. These costs typically cover the drilling rig alone, and don’t consider the costs of necessary supporting equipment and supplies. For example, costs for

PDC (polycrystalline diamond compact) drill bits , used to cut into the earth, alone can be in the thousands of dollars.

Given that the success of finding commercially producible-sized hydrocarbon reservoirs is approximately 1 in 10 chances, oil companies – out of sheer necessity – seek to minimize the cost of failed wildcats by exhausting all reasonable indirect methods of locating hydrocarbons first.

Seismic surveys, using a variety of sonic wave producing guns and extra-sensitive listening devices, allow geophysicists to obtain profiles (cross-sections) of subsurface rock at great depths. If a trap of some sort can be deduced from the sub-surface reflections, there is a chance that oil or gas can be found.

Gravitational and magnetic surveys are flown by aircraft over areas on land and sea to identify the geophysical properties which might suggest the presence of hydrocarbon bearing traps.

Ultimately, though, it is only by drilling the well that the indirect observations will be confirmed.

Crude Oil Price

Crude Oil Price

To understand the importance of the crude oil price per barrell, one needs to consider its relationship with oil’s products…
One month, the cost of regular-grade gasoline is $2 per gallon, the next month it is over $3! Diesel fuel prices are less than gasoline one day, and gasoline is cheaper the next day! Electricity rates, generated from natural gas combustion, are stable all winter, but you can’t afford to heat your home with heating oil because of higher prices (click to see current oil prices) . What’s the deal?

The deal is, hydrocarbon (crude oil and natural gas) is a global commodity. Its refined products are the backbone of business and industry around the globe.

Supply and demand principles apply to oil produced in the Middle East, Asia, Europe, North America and everywhere else – regardless of whether a society embraces socialist or democratic doctrines.

International demand for oil has risen. Consequently, excess capacity is lean. Supply hiccups due to production/shipping/refining bottlenecks and revolutions and rumors of war, can and do cause oil and gas prices to spike. In one violent act, Mother Nature can wreak havoc on operations, critically damaging infrastructure on a regional level, and preventing crude deliveries.

High oil prices cause a ripple effect on downstream, refined products, and global financial markets which recognize its importance.

But, operational constraints, acts of God, and malfunctions are not the only cause of oil price spikes. Oil producing governments and cartels, like OPEC, have artificially curtailed production supply in the past to affect oil prices in their favor.

The public has often accused independent oil companies, oil speculators, and refineries of underhanded dealings too, reducing supply to artificially inflate prices. This is an easy assumption to make when oil companies report record profits during times of limited supply. However, what is not often discussed is the role federal and local governments play in pricing and market requirements.

Crude oil is often refined in localities near their intended market. This is because local agencies have established their own standards for gasoline and other refined products in response to federal mandates and requirements. Reformulated gas, MTBE additives, ethanol use, and minimum Reid Vapor Pressures (RVP) requirements, amongst others add to local complexities.

What are acceptable characteristics and contents for gasoline in Chicago, Illinois may not be acceptable in San Francisco, California. Folks in New England often count on heating oil to heat their homes in winter, while the residents of southwestern United States typically use electricity and natural gas for the same purpose.

This variation in local market requirements can often lead to price spikes when problems arise, which can originate anywhere in the process, from an oil field to a refinery – some scheduled, and some not.

Oil companies, both independent and country-run, are in the business to make profits for themselves and their shareholders. As a result, the costs of exploring, developing, producing, refining and transporting the oil in its raw state to its ultimate refined output is included in the cost of each gallon of gasoline or other such product sold.

In addition, governments can and do levy taxes on oil products, increasing the burden on the individual and corporate consumer.

So, how does oil pricing work?

Crude oil’s value is based on its refined use. The primary use dictated by current global demand is for fuels like gasoline, diesel, heating oil, and jet fuel to run the equipment that support our ways of life. The various characteristics/properties of crude from around the world – referred to euphemistically in industry jargon as light, sweet, intermediate, sour, heavy, etc. – contain differing amounts of the various hydrocarbons and impurities. Their locations around the globe also speak to the costs of getting the oil to local refineries and markets – thereby establishing their relative value for the products in demand.

So, with all the different combinations of crude, how does anyone keep the relative ratings straight? Is Kern River crude more valuable than Nigeria’s Bonny Light? Well, that depends on the end product that is desired, where it is to be refined, and…the market price (see current prices). To ease comparisons, the two predominant crude oil exchanges: The New York Mercantile Exchange (NYMEX) and The International Petroleum Exchange (IPE), based in London, England, have established benchmark crudes from which other crudes are compared. In New York, the benchmark is West Texas Intermediate (WTI) crude oil, while in London it is the North Sea’s Brent crude.

The price of crude oil for immediate delivery (spot price) is set by the transactions that occur at the exchanges (essentially at NYMEX and IPE) throughout the day. The transactions are made based on the sellers’ and purchasers’ assessments of supply and demand.

Kern River crude’s value comparison with WTI or Brent and likewise, Nigeria’s comparison with WTI or Brent allows a buyer to purchase the best valued crude. Along with the benchmark, the benchmark crude oil’s delivery terms are also specified with the exchanges. For example, the spot price for WTI is in Cushing, Oklahoma; for natural gas, it is at Henry’s Hub in Erath, Louisiana; and for gasoline and heating oil it is at New York Harbor.

Oil Location

Oil Location

Oil is found in underground pools of oil called reservoirs. This oil location is not what one might typically expect when considering the term “pool”. It is impossible to go swimming in these pools! Industry experts use the term “pool” to define accumulations of hydrocarbon in zones of subsurface rock. (see oil accumulation). What? How can oil reside in rock?
Well, if you were to zoom in on a chunk of rock, let’s say a sandstone (down to about 0.000001 meters!), you would see thousands of little flecks of stone stuck together with spaces in between them. These spaces are called pores and the term porosity refers to the percentage of pore space to little stones over a given area.

It is within these pore spaces that oil, gas and water reside.

The rock containing the hydrocarbon is called the reservoir rock, and can be a variety of rock types, but is typically a sandstone or limestone. This is due to the relatively high porosities these rock types possess. High quality sandstone reservoirs can have porosities in excess of 25%.

High porosities usually mean higher reserves potential.

Another term used to describe the quality of a reservoir is permeability. Permeability is the measure of the connectivity of the pore spaces to each other. If the pore spaces were not connected to each other, oil would not be able to flow, regardless of whether or not there was good porosity.

Industry experts experience great difficulty (i.e., expense) producing poor permeability reservoirs.