Everything You Need to Know About Oilwell Drilling

1.1. Earliest known drilling

The earliest known oil wells were drilled in China during the 6^th century. Using drill bits attached to bamboo poles, they dug wells about 800 ft (240 m) deep. Oil produced was transported via bamboo pipelines and was used for early lighting and heating applications.

1.2. Early technology developments

Effects from the Industrial Revolution lead to an increased demand for a cheaper, more efficient fuel than coal. This demand led to Colonel Edwin Drake’s famous 1859 discovery of oil in Pennsylvania, which marked the first commercial well drilled in North America. The first modern wells were drilled by using a ‘cable-tool’ system that was raised and dropped to the earth percussively to create a wellbore. The year 1901 is marked for what is often identified as the most famous and influential oil well drilled in the Spindletop Oilfield located in South East Texas. The success of this oilfield influenced the introduction and popularity of the rotary drilling system, which became the globally accepted preferred method of drilling. Parallel to the entry of the rotary drilling system, other key technologies were developed, such as the introduction of the derrick/drawworks system, the tricone drill bit, and the first recorded use of drilling mud.

Los Angeles oil field near 1st Street and Glendale Boulevard, August 20, 1901 (Wikimedia Commons).

2.1. Drilling methods

Vertical drilling

Vertical drilling is considered the traditional drilling method for accessing reservoirs directly beneath the surface. Once the only method of extracting oil and gas, vertical drilling has become a less common method of drilling due to the advancement of horizontal and directional drilling technologies. Vertical wells are considered simple and offer some initial cost savings at startup by requiring less equipment and labour. In larger formation zones, multiple vertical wells are required to effectively produce oil & gas, which can negate some of the initial cost savings. Today, vertical wells are mostly used during the exploratory phase in evaluating the potential of new oil and gas zones.

Horizontal drilling

As the 20th century came to an end, technology was quickly evolving, paving the way for more precise drilling capabilities through the use of directional or steerable drilling equipment. Wells are considered horizontal when they approach a drilling angle 85-90˚ from vertical. Horizontal drilling, also called directional drilling, facilitates an increase of production volumes from a single wellbore by accessing a larger surface area of an oil and gas zone.

2.2. Drilling mud development

Drilling mud types/purposes (use of our products)

First utilised during the drilling of the famous Spindletop Oilfield in 1900, drilling mud was invented to help remove the unconsolidated mixture of sand and clays debris generated by the drilling process. This mixture is very unstable, causing it to collapse on top of the drill bit and increase the difficulty of drilling operations. To resolve this issue, circulation of freshwater was introduced to aid in the removal of the debris. Freshwater mixed with the sand and clay formed a viscous solution that would be later coined as “mud” or drilling mud. The mud not only removed debris from the wellbore. It also formed a filmed layer on the sides of the wellbore that added to the stability of the hole. As time and knowledge progressed, the mud circulating systems became an integral part of all drilling rig operations. Drilling mud compositions became more complex over the years, and they are now custom-designed based on specific formation types, regions, and environmental requirements. The three most common types of drilling muds are water-based, oil-based and synthetic-based. Depending on location and local environmental regulations, any of the three types, or a combination, could be used during the drilling process.

Drilling mud systems are now not only used for removing debris. They also help improve drilling rates, control formation pressures and extend the life of drill bits by providing cooling and lubrication. Lignosulfonates are a natural fit for reducing the viscosity of water-based muds due to their water solubility and well-known proficiency for deflocculation. With appropriate dosage, our BioDrill TM products can assist in providing faster drilling rates.

Fluid migration – FLCA's (use of our products)

Fluid loss control additives, or FLCA’s, were developed to stabilise drilling muds faced with various challenges in the drilling process. FLCA’s reduce the tendency of drilling mud to flow into the micropores of a formation by forming a barrier called a filter cake. FLCA’s create filter cakes by physically plugging these pores themselves or acting as a clay deflocculant enabling clay particles to plug the pores. Failure to properly control fluid loss can result in irreversible changes to the drilling mud’s density and rheology, creating wellbore instability. Commonly used FLCA’s are clays, dispersants, and polymers.

Chemical issues – use of H₂S scavengers

Hydrogen Sulfide (H₂S) is an extremely hazardous substance encountered during some drilling options. Even in a relatively small concentration, H₂S gases can be quite deadly. Beyond health hazards, H₂S can also create costly corrosion damage to equipment due to its corrosiveness to metal. H₂S scavengers are added to drilling muds to react directly with H₂S, converting it to a more inert form. Read more about our solutions for H₂S scavengers.

2.3. Use of cemented case hole

Casing

Casing was first introduced during the early 1900s, originally as part of the drilling process. The casing was rammed into the ground in sections to create the first several hundred feet of a well. Its purpose was to prevent debris from shallow zones from falling on the drilling assembly. Cement was later added to strengthen the well and protect freshwater zones and other vital underground zones. Cement is pumped down the inside of the casing and, as resistance develops, forced down by a rubber plug. Cement is also pumped to the outside of the casing through the bottom under pressure into the space between the wellbore and the outside of the casing, known as the annulus. Once the cement has hardened in the annulus, the drilling operation may move on to the next section of drilling, or the well will be completed for production. Some wells have multiple cemented casing sections that range in decreasing diameters as depth increases. As the wellbore depth increases, the temperature inside the well also increases due to the natural heat generated from the formation and friction from drilling. These temperatures can reach +400°F (+205°C). To prevent the cement from prematurely setting, fluid loss additives, retardants and dispersants are added during the blending process.

Brunch of casing laid out on the floor for well construction

Use of retarders (& complexities, e.g., temperature, pressure, etc.)

Cement retarders extend the time it takes for cement to harden by slowing down the reaction process when water is introduced to the dry cement. The desired thickening time is determined by the time it takes to pump the cement through the casing and into the annulus, plus the additional time to account for equipment issues. The amount of cement retarder required is determined in a lab utilising a consistometer. The consistometer allows the simulation of wellbore conditions that the cement will encounter during pumping, such as temperature, pressure, and pump rate changes. Once the desired simulated thickening time is achieved by adjusting additive concentrations on a lab-scale, the cement slurry design composition is complete and ready to scale up to bulk volumes. Retarders and other additives can be added to cement in dry powder form by blending directly with the cement at bulk dry blending facilities. Bulk dry blending is the most common method for adding various additives to cement prior to mixing for downhole pumping. It is also possible to blend liquid additives with the cement during the mixing process on job sites directly into the cement slurry or mix water if necessary. Mixing liquid additives is primarily utilised in offshore drilling operations or when bulk dry blending facilities are not available. The most common type of retarders used are lignosulfonates.

Use of cement dispersants (Use of our products)

Dispersants are added to cement slurries to improve mixing and pumpability. They are used to ensure that the cement slurry does not become excessively viscous at the required slurry density. Cement density is increased by reducing the water to cement content ratio, which also causes viscosity to increase. Other additives contributing to increases in viscosity are fumed silica, and fluid loss and free water control additives. While dispersants should not retard, most available dispersants do moderately increase thickening time. Dispersant concentrations must be carefully monitored to prevent undesirable conditions such as overdispersion or over retardation. Common types of dispersants are naphthalene sulfonates, hydroxycarboxylic acids and lignosulfonates. Read more about our solutions for cement retarders and cement dispersants.

Wellbore completion begins after the last section of a well is drilled and cemented in place. The wellbore is filled with brine, also called completion fluid. The completion fluid content can vary depending on formation type and availability of chemicals. The most common completion fluid type is potassium chloride brine, or “KCL water”, which is used to prevent swelling of clays and shales when the casing is perforated for production. Other additives such as filtration control agents, viscosifiers, scavengers, surfactants and corrosion inhibitors may be added to completion fluids as well, depending on well conditions.

Fracking

Hydraulic fracturing, also known as fracking, is a well stimulation technique that utilises pressurised fluids containing sand, also called proppant, to increase production volumes of a well. Fracking was first commercially introduced in the 1950s and has since become a commonly used technique for bringing a well online for production. During the earlier periods, fracking was used to improve flow near the wellbore, where natural passages in the formation became clogged and damaged by drilling fluids. Fracking technology advances in the early 2000’s made oil shale formations, once considered unobtainable resources, a viable source of production. Oil shale formations are the most abundant source of oil, with proven discovery on almost all continents. Shale is a very porous formation but has very low permeability, which prevents trapped oil from easily flowing to the wellbore. Fracking creates fractures in the shale formation, and the proppant carried in the fracking fluid is left in place to create a path for the trapped oil to flow back to the wellbore. Fracking fluids are specifically designed for the region and formation types. The amount of proppant carried in the fracking fluid is determined by the pressure acting on the formation. Once the required proppant concentration is determined, the fracking fluid must be designed to carry the proppant through the fracking equipment, down the wellbore and into the formation. The most common types of fracking fluids are conventional linear gel, borate-crosslinked gel, organometallic-crosslinked gel and slickwater fluids. Commonly used chemicals are acids, biocides, corrosion inhibitors, crosslinkers, friction reducers, scale inhibitors and surfactants.

Once completion operations have successfully been completed, a well can be brought online for production. Equipment for processing, storage and transportation are brought onto the well site. From this point, the well will be in maintenance mode. Periodically production chemicals may be needed to treat well conditions such as excess scale, precipitates, asphaltenes, paraffin, emulsions and corrosion. A properly managed well can provide several years of production.