Analysis: Norway Oil Production Falls, Gas Production Rises

Norway oil production has declined over the past 10 years from 3.1 million b/d in 1999 to 2.3 million b/d in 2009, according to the BP Statistical Review of World Energy 2010. This decline can be attributed to the maturation of existing large oil fields offshore Norway. Norway's proved oil reserves also have declined from 10.9 billion barrels in 1999 to 7.5 billion in 2008. The Norwegian Petroleum Directorate (NPD) said that Norway has been unable to offset the production decline from existing fields with resources produced from new discoveries, and that "determined efforts are needed now to stem annual declines in production," said Norway Minister of Petroleum and Energy Terje Riis-Johansen. These efforts include more exploratory and development well drilling and enhanced oil recovery. NPD estimates that oil production for 2010 will be somewhat lower than in 2008 at 108.7 million Sm3 or 1.87 Mb/d. From 2010 through 2014, oil production is expected total 491 million Sm3, or 160 million Sm3 less than the preceding five-year period. However, Norwegian natural gas production has flourished in the past 10 years, thanks to field such as Ormen Lange and Snohvit, which has increased Norwegian gas exports. Norwegian gas production has grown from 48.5 billion cubic meters in 1999 to 103.5 billion cubic meters last year, according to the BP Statistical Review of World Energy 2010. Norway's proved natural gas reserves also grew from 1.25 Tcm in 1999 to 2.22 Tcm in 2008. Natural gas production has risen as oil and gas companies moved northward into underexplored areas as additional exploration acreage has been gradually opened; these underexplored areas contain large gas reserves. As a result, a number of gas fields have been developed and a comprehensive gas transport infrastructure has been established, making it possible to develop additional gas resources. Gas production is expected to grow from an estimated 105 billion Sm3 this year to 112.2 billion Sm3 in 2014. NPD estimates that only 40 percent, or 5.3 billion standard cubic meters of oil equivalent (scm o.e.), of petroleum resources on the Norwegian shelf has been produced. Total remaining recoverable resources is estimated at 8.1 billion scm o.e., including 4.8 billion scm o.e. of proven resources and undiscovered resources of 3.3 billion scm o.e. NPD estimates that 35 percent of undiscovered resources lies in the North Sea, 35 percent in the Norwegian Sea and 30 percent in the Barents Sea. NPD has set a goal of reserves growth on the Norwegian Continental Shelf of 800 million scm of oil before 2015. To meet this goal, NPD said Norway must increase recovery from producing fields, develop discoveries in the vicinity of existing infrastructure, drill more development wells and operate fields in a more cost-efficient manner. Field maintenance also has impacted Norway's oil and gas production in recent months. NPD reported that average daily production in June 2010 was about 1.87 million barrels of oil, natural gas liquids and condensate, 324,000 b/d less than in May 2010. Gas production was about 8.5 billion Sm3, or .5 billion Sm3 less than in the previous month. NPD attributed the lower production to closures of the fields in the Ekofisk area for planned maintenance, while the Vale field was closed due to technical problems. Heidrun also was closed June 1 through June 26 due to maintenance, while Gullfaks C was closed due to well problems

Rotary Drilling

Rotary drilling uses a sharp, rotating drill bit to dig down through the Earth's crust. Much like a common hand held drill, the spinning of the drill bit allows for penetration of even the hardest rock. The idea of using a rotary drill bit is not new. In fact, archeological records show that as early as 3000 B.C., the Egyptians may have been using a similar technique. Leonardo Da Vinci, as early as 1500, developed a design for a rotary drilling mechanism that bears much resemblance to technology used today. Despite these precursors, rotary drilling did not rise in use or popularity until the early 1900's. Although rotary drilling techniques had been patented as early as 1833, most of these early attempts at rotary drilling consisted of little more than a mule, attached to a drilling device, walking in a circle! It was the success of the efforts of Captain Anthony Lucas and Patillo Higgins in drilling their 1901 'Spindletop' well in Texas that catapulted rotary drilling to the forefront of petroleum drilling technology.
While the concept for rotary drilling - using a sharp, spinning drill bit to delve into rock - is quite simple, the actual mechanics of modern rigs are quite complicated. In addition, technology advances so rapidly that new innovations are being introduced constantly. The basic rotary drilling system consists of four groups of components. The prime movers, hoisting equipment, rotating equipment, and circulating equipment all combine to make rotary drilling possible.
Prime Movers
The prime movers in a rotary drilling rig are those pieces of equipment that provide the power to the entire rig. Up until World War II, rotary rigs were traditionally powered by steam engines. Diesel engines became the norm after the war. Recently, while diesel engines still compose the majority of power sources on rotary rigs, other types of engines are also in use. Natural gas or gasoline engines are commonly used, as are natural gas or gasoline powered reciprocating turbines, which generate electricity on site. The resulting electricity is used to power the rig itself. Other rotary rigs may use electricity directly from power lines. Most rotary rigs these days require 1,000 to 3,000 horsepower, while shallow drilling rigs may require as little as 500 horsepower. Rotary rigs designed to drill in excess of 20,000 feet below surface may require much more than 3,000 horsepower. The energy from these prime movers is used to power the rotary equipment, the hoisting equipment, and the circulating equipment, as well as incidental lighting, water, and compression requirements not associated directly with drilling.

Working on an Onshore Drilling Rig

Source: Anadarko Petroleum Corporation

Hoisting Equipment
The hoisting equipment on a rotary rig consists of the tools used to raise and lower whatever other equipment may go into or come out of the well. The most visible part of the hoisting equipment is the derrick, the tall tower-like structure that extends vertically from the well hole. This structure serves as a support for the cables (drilling lines) and pulleys (draw works) that serve to lower or raise the equipment in the well. For instance, in rotary drilling, the wells are dug with long strings of pipe (drillpipe) extending from the surface down to the drill bit. If a drill bit needs to be changed, either due to wear and tear or a change in the subsurface rock, the whole string of pipe must be raised to the surface. In deep wells, the combined weight of the drillpipe, drill bit, and drill collars (thicker drillpipe located just above the bit) may be in excess of thousands of pounds. The hoisting equipment is used to raise all of this equipment to the surface so that the drill bit may be replaced, at which point the entire chain of drillpipe is lowered back into the well.

Positioning the Hoisting Equipment

Source: Anadarko Petroleum Corporation

The height of a rigs derrick can often be a clue as to the depth of the well being dug. Drillpipe traditionally comes in 30ft sections, which are joined together as the well is dug deeper and deeper. This means that even if a well is 20,000 feet deep, the drill string must still be taken out in 30 foot sections. However, if the derrick is tall enough, multiple joints of drillpipe may be removed at once, speeding up the process a great deal. Rotating Equipment
The rotating equipment on a rotary drilling rig consists of the components that actually serve to rotate the drill bit, which in turn digs the hole deeper and deeper into the ground. The rotating equipment consists of a number of different parts, all of which contribute to transferring power from the prime mover to the drill bit itself. The prime mover supplies power to the rotary, which is the device that turns the drillpipe, which in turn is attached to the drill bit. A component called the swivel, which is attached to the hoisting equipment, carries the entire weight of the drillstring, but allows it to rotate freely.
The drillpipe (which, when joined together, forms the drillstring) consists of 30ft sections of heavy steel pipe. The pipes are threaded so that they can interlock together. Drillpipe is manufactured to meet specifications laid out by the American Petroleum Institute (API), which allows for a certain degree of homogeneity for drillpipes across the industry. The drillpipe is a very heavy, strong pipe, but can be quite flexible when used in slant or horizontal drilling applications.
Below the drillpipe are drill collars, which are heavier, thicker, and stronger than normal drillpipe. The drill collars help to add weight to the drillstring, right above the bit, to ensure there is enough downward pressure to allow the bit to drill through hard rock. The number and nature of the drill collars on any particular rotary rig can be altered depending on the down hole conditions experienced while drilling.

Diamond Studded Drill Bits

Source: Sandia National Laboratory (left), DOE - National Energy Technology Laboratory

The drill bit is located at the bottom end of the drillstring, and is responsible for actually making contact with the subsurface layers, and drilling through them. The drill bit is responsible for breaking up and dislodging rock, sediment, and anything else that may be encountered while drilling. There are dozens of different drill bit types, each designed for different subsurface drilling conditions. Different rock layers experienced during drilling may require the use of different drill bits to achieve maximum drilling efficiency. It can be a long process to change bits, due to the fact that the whole drill string must be removed; but using the correct drill bit, or replacing a worn bit, can save a great deal of time during drilling. Drill bits are chosen given the underground formations expected to be encountered, the type of drilling used, whether or not directional drilling is needed, the expected temperatures underneath the Earth, and whether or not cores (for logging purposes) are required. There are four main types of drill bits, each suited for particular conditions.

• Steel Tooth Rotary Bits are the most basic type of drill bit used today.
• Insert Bits are steel tooth bits with tungsten carbide inserts.
• Polycrystalline Diamond Compact Bits have polycrystalline diamond inserts attached to the carbide inserts found in Insert Bits.
• Diamond Bits have industrial diamonds implanted in them, to drill through extremely hard rock formations. Diamond bits are forty to fifty times harder than traditional steel bits, and can thus be used to drill through extremely hard rock without dulling overly quickly.

In addition to these main types of drill bits, hybrid bits, combining the features of various types of bits, can be used. If core samples are required for logging purposes, core bits are designed to drill and obtain these samples. There are a great number of different designs for drill bits, including tricone roller bits, button bits, tapered bits, fishtail bits, and mill bits. Each of these bits has specifically designed drilling traits. The fishtail bit, for instance, is designed to enlarge the drill hole above the drill bit, and the mill bit is designed to mill away metal scraps or objects found in the well. The drill bit, in addition to being very useful, is also very expensive. It is thus up to the drilling engineer to ensure that the correct bit is used at the correct time, to allow for maximum drilling efficiency, with minimum wear and tear on the valuable bit.

Lowering the Bit and Drill Collar into the Well Hole

Source: NGSA

Circulating System
The final component of rotary drilling consists of the circulating system. There are a number of main objectives of this system, including cooling and lubricating the drill bit, controlling well pressure, removing debris and cuttings, and coating the walls of the well with a mud type-cake. The circulating system consists of drilling fluid, which is circulated down through the well hole throughout the drilling process.
Typically, liquid drilling fluids are used. The most common liquid drilling fluid, known as 'mud', may contain clay, chemicals, weighting materials, water, oil, or gases. 'Air drilling' is the practice of using gasses as the drilling fluid, rather than a liquid. Gases used include natural gas, air, or engine exhaust. Air drilling can significantly cut down on drilling time, as well as drilling fluid costs. The drilling fluid, much like the bit, is custom designed and chosen depending on what type of subsurface conditions are expected or experienced. For example, if drilling is occurring through underground salt formations, freshwater would not be used, as this would risk dissolving the subsurface salt. Similarly, if drilling near sources of fresh water, salt water would not be used for fear of contaminating the fresh water.
The drilling fluid chosen must have a number of properties to allow it to accomplish its tasks. It must be light and thin enough to circulate through the drill bit, cooling the bit as it drills as well as lubricating the moving parts. The fluid must be heavy enough to carry drill cuttings away from the bit and back to the surface, as well as control upward pressure that may be experienced in the well to prevent blowouts. The drilling fluid engineer ensures that the weight of the drilling fluid is greater than the upward pressure of escaping gas that may be encountered while drilling. In addition, the drilling fluid must be thick enough to coat the wellbore with a cake, which serves to temporarily seal the walls of the well until casing can be installed.
The circulating system consists of a starting point, the mud pit, where the drilling fluid ingredients are stored. Mixing takes place at the mud mixing hopper, from which the fluid is forced through pumps up to the swivel and down all the way through the drill pipe, emerging through the drill bit itself. From there, the drilling fluid circulates through the bit, picking up debris and drill cuttings, to be circulated back up the well, traveling between the drill string and the walls of the well (also called the 'annular space'). Once reaching the surface, the drilling fluid is filtered to recover the reusable fluid.

An Onshore Drilling Rig

Source: DOE - EREN

In addition to the fluid itself regulating downhole pressures encountered while drilling, a device known as the 'blowout preventer' is situated on the well casing below the deck of the rig. A blowout can occur when uncontrolled underground oil or gas pressure exerts more upward pressure than the drilling fluid itself can offset. The blowout preventer can consist of hydraulically powered devices that can seal off the well quickly and completely, preventing any potential for a well blowout should extreme downhole pressures be encountered. Pressure release systems are also installed to relieve the great pressure that can be experienced in a blowout situation.












Source

NaturalGas.org

Onshore Drilling

Onshore Drilling

Source: ChevronTexaco Corporation Drilling into the Earth in the hopes of uncovering valuable resources is nothing new. In fact, the digging of water and irrigation wells dates back to the beginning of recorded history. At first, these wells were primarily dug by hand, then by crude stone or wood tools. Metallurgy brought about the use of iron and bronze tools to delve beneath the Earth's surface, and innovations led to more efficient ways of removing debris from the newly dug hole. The first recorded instance of the practice of 'drilling' holes in the ground came about around 600 B.C., when the Chinese developed a technique of repeatedly pounding bamboo shoots capped with metal bits into the ground. This crude technology was the first appearance of what is now known as 'percussion drilling'; a method of drilling that is still in use today. Much advancement has been made since these first bamboo drilling implements, with the realization of the value and increased demand for subsurface hydrocarbons. This section will cover the basics of modern onshore natural gas drilling practices. There are two main types of onshore drilling. Percussion, or 'cable tool' drilling, consists of raising and dropping a heavy metal bit into the ground, effectively punching a hole down through the Earth. Cable tool drilling is usually used for shallow, low pressure formations. The second drilling method is known as rotary drilling, and consists of a sharp, rotating metal bit used to drill through the Earth's crust. This type of drilling is used primarily for deeper wells that may be under high downhole pressure. Cable Tool Drilling Cable tool, or percussion drilling is recognized by many as the first drilling method employed to dig wells into the Earth for the purpose of reaching petroleum deposits and water. This method is still in use in some of the shallow wells in the Appalachian Basin, although rotary drilling has taken over the bulk of modern drilling activities. The basic concept for cable tool drilling consists of repeatedly dropping a heavy metal bit into the ground, eventually breaking through rock and punching a hole through to the desired depth. The bit, usually a blunt, chisel shaped instrument, can vary with the type of rock that is being drilled. Water is used in the well hole to combine with all of the drill cuttings, and is periodically bailed out of the well when this 'mud' interferes with the effectiveness of the drill bit. Early Percussion Rigs in Pennsylvania - Late 1800's Source: Office of Fossil Energy, DOE Cable tool drilling has historically taken many forms. In the early days of percussion drilling, equipment was very crude compared to today's technology. The 'springpole' technique, used in the early 1800's, consisted of a flexible pole (usually a tree trunk) anchored at one end, and laying across a fulcrum, much like a diving board. The flexible pole, or springpole, would have a heavy bit attached at the loose end. In order to get the bit to strike the ground, workers would use their own body weight to bend the pole towards the ground, allowing the bit to strike rock. The tension in the pole would spring the bit free, should it become stuck in the ground. Much advancement has been made since these early percussion rigs. In fact, it was from cable tool drilling that one of the most important drilling advancements was made. In 1806, David and Joseph Ruffner were using the springpole technique to drill a well in West Virginia. In order to prevent their well from collapsing, they used hollow tree trunks to reinforce the sides of the well, and to keep water and mud from entering the well as they dug. They are credited as the first drillers to use a casing in their well - an advancement that made drilling much more efficient and easily accomplished. It is believed by many that 'Colonel' Drake's 1856 well achieved success due to the use of steel casing to reinforce the well. Drake's well was drilled using steam powered cable tool drilling methods. A Modern, Mobile Cable Tool Drilling Rig Source: Anadarko Petroleum Corporation Innovations, such as the use of steam power in cable tool drilling, greatly increased the efficiency and range of percussion drilling. Conventional man-powered cable tool rigs were generally used to drill wells 200ft or less, while steam powered cable tool rigs, consisting of the familiar derrick design, had an average drilling depth of 400 to 500 feet. The deepest known well dug with cable tool drilling was completed in 1953, when the New York Natural Gas Corporation drilled a well to a depth of 11,145 ft Source NaturalGas.org.