For questions on access or troubleshooting, please check our FAQs , and if you can''t find the answer there, please contact us. All Rights Reserved. Under the terms of the licence agreement, an individual user may print out a PDF of a single chapter of a title in Oxford Handbooks Online for personal use for details see Privacy Policy and Legal Notice. Oxford Handbooks Online. Publications Pages Publications Pages. Recently viewed 0 Save Search. In the Cargo Muchacho mountains of Imperial County, California , Southern Empire owns percent of the historical gold-producing American Girl mine property and holds options to acquire a percent interest in the adjacent 2,hectare 5,acre Oro Cruz property located approximately During that time, gold was recovered by either heap leaching of lower-grade, or milling of higher-grade ores until AGMJV operations ceased in late because of declining gold prices leaving the Oro Cruz property with many gold exploration targets in addition to the historical inferred resource estimate, reported In by Lincoln Mining Corp.
For further information on Southern Empire please visit: www. Information provided in this news release may contain forward-looking information or forward-looking statements that are based on assumptions as of the date of this news release.
Such information or statements reflect management's current estimates, beliefs, intentions, and expectations and are not guarantees of future performance.
Southern Empire cautions that all forward-looking statements are inherently uncertain and that actual performance may be affected by many material factors, many of which are beyond its respective control.
Such factors include, among other things: risks and uncertainties relating to Southern Empire's limited operating history, the need to comply with environmental and governmental regulations, results of exploration programs on its projects, and those risks and uncertainties identified in its annual and interim financial statements and management discussion and analysis.
Once the casing is installed, tubing is inserted inside the casing, from the opening well at the top to the formation at the bottom. The hydrocarbons that are extracted run up this tubing to the surface.
The production casing is typically 5 to 28 cm 2 in with most production wells being 6 inches or more. Production depends on reservoir, bore, pressure, etc. A packer is used between casing and tubing at the bottom of the well. In essence, completion consists of deciding on the characteristics of the intake portion of the well in the targeted hydrocarbon formation.
There are a number of types of completions, including:. Open hole completions are the most basic type and are only used in very competent formations that are unlikely to cave in.
An open hole completion consists of simply running the casing directly down into the formation, leaving the end of the piping open without any other protective filter. Conventional perforated completions consist of production casing run through the formation. The sides of this casing are perforated, with tiny holes along the sides facing the formation, which allows hydrocarbons to flow into the well hole while still providing a suitable amount of support and protection for the well hole.
These were essentially small guns lowered into the well that sent off small bullets to penetrate the casing and cement. This consists of small, electrically-fired charges that are lowered into the well.
When ignited, these charges poke tiny holes through to the formation, in the same manner as bullet perforating. Sand exclusion completions are designed for production in an area that contains a large amount of loose sand. These completions are designed to allow for the flow of natural gas and oil into the well, while preventing sand from entering. The most common methods of keeping sand out of the well hole are screening or filtering systems.
Both of these types of sand barriers can be used in open hole and perforated completions. Permanent completions are those in which the completion and wellhead are assembled and installed only once. Installing the casing, cementing, perforating and other completion work is done with small-diameter tools to ensure the permanent nature of the completion. Completing a well in this manner can lead to significant cost savings compared to other types.
Multiple zone completion is the practice of completing a well such that hydrocarbons from two or more formations may be produced simultaneously, without mixing with each other. For example, a well may be drilled that passes through a number of formations on its way deeper underground, or it may be more desirable in a horizontal well to add multiple completions to drain the formation most effectively.
Drainhole completions are a form of horizontal or slanted drilling. This type of completion consists of drilling out horizontally into the formation from a vertical well, essentially providing a drain for the hydrocarbons to run down into the well. These completions are more commonly associated with oil wells than with natural gas wells.
Dry completion means that the well is onshore or on the topside structure on an offshore installation. Subsea wellheads are located underwater on a special sea bed template. These must be able to withstand pressures of up to MPa 1, Bar.
A typical Christmas tree, composed of a master gate valve, a pressure gauge, a wing valve, a swab valve and a choke is shown above. The Christmas tree may also have a number of check valves.
The functions of these devices are explained below. Ill: Vetco Gray. At the bottom we find the casing head and casing hangers. The casing is screwed, bolted or welded to the hanger. Several valves and plugs are normally fitted to give access to the casing. This permits the casing to be opened, closed, bled down, and in some cases, allow the flowing well to be produced through the casing as well as the tubing.
The valve can be used to determine leaks in casing, tubing or the packer, and is also used for lift gas injection into the casing. The tubing hanger also called a donut is used to position the tubing correctly in the well. Sealing also allows Christmas tree removal with pressure in the casing.
Master gate valve. The master gate valve is a high quality valve. It provides full opening, which means that it opens to the same inside diameter as the tubing so that specialized tools may be run through it. It must be capable of holding the full pressure of the well safely for all anticipated purposes. This valve is usually left fully open and is not used to control flow.
Pressure gauge. The minimum instrumentation is a pressure gauge placed above the master gate valve before the wing valve. In addition, other instruments such as a temperature gauge are normally fitted. Wing valve. The wing valve can be a gate or ball valve.
When shutting in the well, the wing gate or valve is normally used so that the tubing pressure can be easily read. Swab valve. The swab valve is used to gain access to the well for wireline operations, intervention and other workover procedures see below. On top of it is a tree adapter and cap that mates with a range of equipment. Variable flow choke valve. The variable flow choke valve is typically a large needle valve. High-quality steel is used in order to withstand the high-speed flow of abrasive materials that pass through the choke, usually over many years, with little damage except to the dart or seat.
If a variable choke is not required, a less expensive positive choke is normally installed on smaller wells. This has a built-in restriction that limits flow when the wing valve is fully open. Vertical tree. Christmas trees can also be horizontal where the master, wing and choke are on a horizontal axis. This reduces the height and may allow easier intervention. Horizontal trees are especially used on subsea wells. The product is piped back through pipelines and risers to the surface.
The main choke may be located topside. The former are for production of oil and gas. Injection wells are drilled to inject gas or water into the reservoir. The purpose of injection is to maintain overall and hydrostatic reservoir pressure and force the oil toward the production wells.
Injection wells are fundamentally the same as production wellheads. The difference is their direction of flow and, therefore, mounting of some directional components, such as the choke.
A free flowing oil well has enough downhole pressure to reach suitable wellhead production pressure and maintain an acceptable well flow. If the formation pressure is too low, and water or gas injection cannot maintain pressure or are not suitable, the well must be artificially lifted. For smaller wells, 0.
Larger wells will be equipped with artificial lift to increase production, even at much higher pressures. Some artificial lift methods are:. On each upward stroke, the plunger lifts a volume of oil up and through the wellhead discharge. On the downward stroke it sinks it should sink, and not be pushed allowing oil to flow though the valve.
The motor speed and torque is controlled for efficiency and minimal wear with a pump off controller PoC. Use is limited to shallow reservoirs down to a few hundred meters, and flows up to about 40 liters 10 gallons per stroke. Installations down to 3. At these depths and power ratings, medium voltage drives up to 5kV must be used.
The valve will open at a set pressure to inject lift gas into the tubing. Several mandrels with valves set at different pressure ranges can be used to improve lifting and startup. Ill: Schlumberger oilfield glossary. Gas lift can be controlled for a single well to optimize production, and to reduce slugging effects where the gas droplets collect to form large bubbles that can upset production. Gas lift can also be optimized over several wells to use available gas in the most efficient way.
In this case, the well flow conditions can be such that liquid starts to collect downhole and eventually blocks gas so that the well production stops. A plunger catcher at the top opens the valve and can hold the plunger, while another mechanism downhole closes the valve. When the plunger reaches the wellhead plunger catcher, the valve opens and allows gas to flow freely for some time while new liquid collects at the bottom.
After a preset time, the catcher releases the plunger and the cycle repeats. Well workover is the process of performing major maintenance on an oil or gas well. This might include replacement of the tubing, a cleanup or new completions, new perforations and various other maintenance works such as the installation of gas lift mandrels, new packing, etc.
Through-tubing workover operation is work performed with special tools that do not require the time-consuming full workover procedure involving replacement or removal of tubing. Well maintenance without killing the well and performing full workover is time-saving and often called well intervention. Various operations that are performed by lowering instruments or tools on a wire into the well are called wireline operations.
Work on the reservoir such as chemical injection, acid treatment, heating, etc. Stimulation serves to correct various forms of structure damage and improve flow. Damage is a generic term for accumulation of particles and fluids that block fractures and pores and limit reservoir permeability. Acids, such as hydrochloric acid HCL are used to open up calcareous reservoirs and to treat accumulation of calcium carbonates in the reservoir structure around the well.
When the pressure is high enough to open the fractures, the process is called fracture acidizing. If the pressure is lower, it is called matrix acidizing.
Hydraulic fracturing is an operation in which a specially blended liquid is pumped down a well and into a formation under pressure high enough to cause the formation to crack open, forming passages through which oil can flow into the well bore.
Slaughter reported yearly production of , barrels of oil from sixty-six wells that were operated by ten producers. Four of those operators-Honolulu, Sid W. With the South Plains line and the Aloco connection to move crude from both the Duggan and the Slaughter areas, drilling continued to increase in During the year Magnolia Pipe Line Company built a gathering system in Slaughter field and a fifty-one-mile, eight-inch carrier to Seminole, Texas, with a capacity of 6, barrels of oil per day.
Expansion in both Duggan and Slaughter fields consisted of gradual and low-risk development of the space that separated them. Operators were so successful in linking the producing sectors that on December 1, , the Railroad Commission ruled that the two fields produced from a common reservoir. The commission officially joined the 54, proved acres of the Duggan and Slaughter areas into one field called Slaughter.
Before merging with Slaughter field, Duggan produced , barrels of oil during from thirty-one wells held by seven operators. Slaughter field reported its production as , barrels of oil from wells.
The yearly combined production of both pools was 1,, barrels of oil. During Slaughter field developed generally in a northward direction, but the field was also enlarged by wells that pushed its boundaries to the northeast, west, and south.
One deep test by Atlantic Company attempted to find a deeper pay zone by drilling to 7, feet, but no evidence of oil was found below the 5,foot Slaughter-producing horizon. When a fourth pipeline was built in by Sid W. Richardson from Slaughter to Wasson field in Gaines County, yearly production sharply increased by fourfold to 4,, barrels of oil from wells.
The 57, proved acres of the field made it the second-largest oil-producing area in the state. From through the field continued to build toward peak production. Its yield of 7,, barrels of oil from 1, wells was greatly exceeded by the 11,, barrels of oil from 1, wells reported in Also in , as the field continued to balloon, Honolulu Oil Corporation constructed a small camp for its employees in Cochran County. Production for doubled the figure and that number enlarged again in , the peak production year, when 23,, barrels of oil came from the 1, wells in the field.
The spur in drilling and production in the early s resulted from a ruling by the Railroad Commission that permitted the drilling of additional wells in each lease of the field. Cumulative production at the end of , which ended the first decade of field production, was a staggering 71,, barrels of oil.
Throughout the second half of the decade, the maturing field remained strong. In Slaughter field produced gas for the first time when it reported a yield of 5.
In October operators in the field successfully opposed the combining of Slaughter and Levelland fields, arguing that the two did not connect and that they produced from separate reservoirs. Gas yields increased through , when they peaked at over million cubic feet, ending the decade with cumulative production of
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