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.
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.