The Well Completion and Production Lesson consists of the following topics

Learning Objectives

Well Completion

Production Tubing

The Wellhead

Well Completions

Offshore Completions

Stimulation and Types

Artificial Lift

Various Pumping Methods

Hydrocarbon Separation

Servicing and Workovers

Enhanced Oil Recovery (EOR) Technology

Technology to Extend Production Life

Plug and Abandonment (P&A) – Onshore

Plug and Abandonment (P&A) – Offshore

Well Completion

In short, well completion simply means deeming the well a commercially viable operation, then preparing the well for production.The most widely held view is that completion begins when a drill bit

first makes contact with a productive reservoir.

Economic success of a well depends in large part on how the well is completed.

A successful completion must first make the optimum mechanical connection between the wellbore and the reservoir. That optimum connection must perform three functions. It must:

let oil or gas into the well, where it can then flow or be pumped to the surface

keep water out of the well

keep the formation from collapsing into the well bore or reservoir.

Production Tubing

After the final string of casing is run and cemented into place, production tubing is run into the hole. It is generally much smaller indiameter than the production casing.

Unlike casing, production tubing hangs from the wellhead and is not cemented into place. This tubing is then easy to remove should any well problems develop in the future.

Today, many production wells have incorporated the use of coiled tubing as shown in the picture. Unlike classic production tubing (manufactured in single joints of pipe), coiled tubing is a continuous reel of flexible tubing.

Tubing Packers

A tubing packer is a circular combination metal and rubber that fits around the production tubing and inside the production casing. As shown in the picture, it provides a tight seal between everything above and below its position.

Packers are used to prohibit well fluids and pressures from entering the production casing. It forces the well fluids to take the path of least resistance to the surface, the production tubing.

Packers also preserve the life of the casing by not allowing well sediment to act as an abrasive against the walls of the casing.

The Wellhead

Reservoirs are typically found at elevated pressures. To equalize the pressure and avoid the excitement of the “gushers” of the early 1900’s, a series of valves and equipment is installed on top of the well. This assembly, or “Christmas tree,” as it is often called becauseit crudely represents a decorated tree, regulates the flow of hydrocarbons out of the well.

The wellhead, pictured on the chart, is located at the base of the treeand the center of the wellbore to:

help support the weight of the production tubing

control the flow rate and pressure of the well fluids

seal the well

Well Completions

The various types of well completions in the wellbore are shown in the chart.

Open-Hole completions require no production casing or liners. Instead the well fluid enters the wellbore and flows freely to the surface via the intermediate casing.

Slotted liners can be used if cement and casing is not technically needed, and if no wellbore stability problems are likely.

To combat the problems of sand or other fines in the production, screens can be placed between the well and the formation. Gravel packing can be used as an additional safeguard and as a means to keep permeability-reducing fines away from the well.

Perforated completion is by far the most common completion method in use today. Perforating is the process of piercing the production casing at specific locations to allow the formation fluids to enter the wellbore and flow to the surface.

Offshore Completions

Offshore completion techniques and equipment are much like those based on land, in that both require some type of multi-valve system

to regulate flow rates and pressures and minimize the risk of blow-outs.

On most fixed platforms the wellhead is located on the deck of the platform (called a surface completion). On floating platforms, or in deep water, the wellhead is located on the sea-floor (called a subsurface or subsea completion).

Stimulation and Types

Regardless of the quantity of hydrocarbons present, oil and gas wells do not always behave as designed. Some require extensive, and expensive, treatments before they can produce economically.

In tight formations with low permeability, fracturing is used to physically crack the rock and create a greater area of flow between the wellbore and the formation. These techniques are called well stimulation and the most common methods are:

Acidizing relies on chemical reactions with the surrounding formations. This method is most effective on carbonate (limestone anddolomite) reservoirs. A scientific cocktail of various chemicals is injected into the well to dissolve the formation. Acidizing can be usedon new wells and is much cheaper to perform than “frac-ing”.

Explosives – Some formations need explosives to create the fractures. Using explosives is a costly process and as a result, are most often used on larger wells that have the capability of justifying the expense.

Hydraulic fracturing is the application of high pressure forcing massive amounts of either oil or water into the formations that surround a reservoir. Commonly referred to as a “frac job” this

pressure causes the formations to break apart causing additional well fluid channels to open up which releases more fluid. Hydraulic fracturing is used in “mature” fields and in a great deal of horizontalwells today (especially shales).

Hydraulic Fracturing

In a typical hydraulic fracturing job, over 350,000 pounds of fluid will be pumped at extraordinarily high pressures down a well, to a pinpoint location, often thousands of feet below the earth’s surface.

In practice, hydraulic fracturing is a highly complex operation performed with the exquisite orchestration of dozens of large trucks, roughly the same number of highly skilled engineers and technicians, a mobile laboratory for real-time quality assurance, and powerful integrated computers.

During the fracturing process, constant measurements of fluid level, pumping rates, and pumping times are performed to maximize the fracture zone, while minimizing any damage to the formation.

LACT Units Measuring and Testing

Once a well is completed, several rounds of testing and measuring areconducted to ensure the economic viability and the production volumes of the well.

LACT (Lease Automated Custody Transfer) Units have drastically changed how oil is tested and measured and are by far the most widely used measurement technique today.

LACT units are self-contained, automated, skid-mounted units found atthe well site, along the pipeline or prior to entering a storage facility.Hydrocarbon ownership changes hands many times before it reaches the consumer and is measured and tested at each point with a LACT unit.

Artificial Lift

Originally, it was thought that well completion meant nothing more than drilling into the pay-zone and letting the oil flow.

However, it quickly became apparent that oil does not have any inherent ability to expel itself from a reservoir, but rather must be displaced from the porous formation in the reservoir. Thus began theconcept of creating and stimulating paths of least resistance to the wellbore.

To maximize the potential of a single well, additional methods of fluid extraction must be utilized. The most common artificial lift methods are “gas” (CO2) lifting and pumping.

Pumping Methods

“Pumping” methods are very common with producers. The three typesare:

Beam Pump

On land wells, “beam” pumping is the most common equipment. Theygo by many names: Walking Beams, Rocking Horse, Pump Jack, etc. Whatever they are called, their operation is very basic. The pump is connected to some type of prime mover, either a diesel engine or electrical motor. The rotation of the prime mover causes a reciprocating motion of the walking beam. The walking beam is connected to a sucker rod (steel or fiberglass) centered over the wellbore that plunges into the well and literally sucks the oil to the surface.

Hydraulic Pump

This pump is very similar to a beam pump because it also uses an engine or motor at the surface and pump at the wellbore. Unlike the beam pump, the hydraulic variety does not use a sucker rod. Instead, hydraulic fluid is pumped downhole to force the reservoir fluids to the surface. Hydraulic pumps are more common on deeper wells and are far less expensive to service and maintain than beam pumps.

Electric Submersible Pump (ESP)

This type of pump is located downhole in the reservoir. Over the years, ESP’s have become popular because of the extra amount of oil that can be recovered from a mature well. ESP’s can be also stacked on top of each other to reach multiple pay zones in a reservoir.

Hydrocarbon Separation

Oil and gas hydrocarbons are not immediately salable when they are pumped from the reservoir. Most well streams are a combination of gas, oil, water, solid sediment and toxic gases that must first pass through a separation process in order to be marketable.

The simplest one separates liquids from gases and heavier liquids fromlighter liquids. In this process, the well stream passes through a seriesof separation tanks where the heavier substance drops to the bottom of the tank. The well stream then must pass through multiple separation units to further purify the hydrocarbons.

Even after multi-stage separation has occurred, the oil is still not at its purest form. Hydrocarbons must have a series of specialized treatments to purify the oil or gas for sale.

Hydrocarbon Treatment

There are two general types of treatments for well fluids described below:

Chemical Treatment – Chemical demulsifiers are added to the reservoir mixture to combine smaller water molecules. As water droplets combine they get big and heavy enough to be separated fromthe oil.

Heat Treatment – When heat is applied to a reservoir mixture, the process also can remove water. Heating must be combined with other

types of treatment to supplement the overall effectiveness of the process.

Servicing and Workovers

At some point in their life, wells will undergo some type of servicing and repairs, called a workover.

Since a drilling rig is used to drill wells that can exceed 20,000 feet, it needs a powerful rotary head to turn the drill pipe to “make hole”.

A workover rig doesn’t have a top or power head. It is just a big winch used to run casing tools or clean out equipment in and out of ahole that is already drilled. These rigs are also used to set well casing and rework an older borehole.

Most of them are very mobile as shown in the picture.

Enhanced Oil Recovery (EOR)

In development of an oil field, the ultimate ability to recover the hydrocarbons in a reservoir can range between 10% and 80%, and depends on:

Reservoir quality and consistency

Well and reservoir fluid properties

Field production strategies

Other geological factors

Once a well has used up all of its natural energy (drives) and pumps have recovered all they can, there could still be as much as 25% – 95% of the oil remaining in the reservoir. In the early days of production, once a well reached this point, it was often plugged and abandoned.

Today, many new techniques are used to increase the amount of oil recovered from a well; thus extending the life of the well. As a group they are called Enhanced Oil Recovery (EOR) techniques.

As the chart shows, in EOR a fluid is injected into the reservoir through an injection well; and the formation fluids are taken out to be treated via a production well.

Extending Production Life

As shown in the chart, economics drives the decision to keep producing from a particular field.

Primary recovery is defined as the ability to drive oil or gas to the surface with normal well operations and existing reservoir pressures. The average global primary recovery factor is 32%. This means that at

abandonment two-thirds of the reserves are still in place in mature basins such as the North Sea or North America.

Secondary recovery techniques like water flooding may bring the recovery factor up to 40%. Here, huge quantities of water are injected into the edges of a producing field to drive the oil (lighter than water) to a collection point.

Tertiary recovery uses heat and steam, complex polymers, surfactants and microbes to increase the recovery even further.

Ultimate recovery is one of the greatest underlying themes for the future of the oil and gas industry. The goal is to leave behind as littlevaluable hydrocarbon resource as possible.

EOR Injection Types

Four basic EOR injection technologies are used today:

Water Injection – Several “injection” wells are drilled in the same reservoir and flooded with water to force the oil up the production string. Technology exists today that allows oil and water to be separated downhole and the water is re-injected into a nearby nonproductive formation and never reaches the surface.

Gas injection – There are two types and both methods require use of compressors located at the surface

Miscible Gas Injection – Carbon dioxide is injected into the well. Here it mixes with and vaporizes the hydrocarbons enabling the oil tofreely flow to the surface. This injection method is sometimes

followed by water injection to increase reservoir output.

Immiscible Gas Injection – Gas is injected into the well to supplementthe existing “natural” pressure of the formation, thereby forcing the oil to the surface.

Chemical Injection requires specially formulated solutions which dissolve and break down barriers or blockages in the formations to increase the flow of oil.

Hot pressurized steam is injected into the well and allowed to soak for some period of time. As the oil heats and reduces viscosity, it begins to flow to the surface