Completions

The Reservoir/Wellbore Connection

Well completions are as old as the petroleum industry itself. In fact, on 27 August 1859, the oil from Colonel Drake’s 691/2-ft well in Titusville, Pennsylvania, had to be pumped to the surface. Pumping that oil was an example of the outflow phase of well completions—that is, methods of transmitting fluids to the surface. This article traces the evolution of inflow—the phase of completion operations that deals with opening the wellbore to the producing formation. (Outflow will be discussed in a later installation of this series.)

In 1859, the petroleum industry consisted of two oil wells in the U.S. producing a total of 2,000 bbl and having a combined value of U.S. $40,000. Suman¹, in his 1921 book Petroleum Production Methods discussed the vastness of an industry that had expanded to 35,000 new wells the previous year in the U.S. alone, at a cost of approximately U.S. $575 million. In the preface, he wrote, “ It is quite probable that, as time goes on, the production of petroleum per well in the U.S. will gradually decline to the point where operators will become very much interested in doing things in a more efficient manner.” That the time would come when operators would give more than a little attention to economy and efficiency was unquestionable. But Suman and those who worked alongside him probably never could have imagined that need would be driven by a global, low-price market for the world’s chief energy source.

There is no question that economy and efficiency drive today’s completion operations. Neither is there any question that creativity, perseverance, and some risk-taking by completions engineers (both in developing new technologies and in continually finding new ways to apply existing techniques) have enabled --- and will continue to enable --- the petroleum industry to produce oil and gas efficiently while lowering the cost per unit and raising net present value. Recently, completion operations have become more specialized, and perception has evolved from the idea of “completion equals plumbing” (i.e., seals, tubulars, valves, and packers) to “completion equals well optimization.”² This change certainly is evident in inflow technologies.

Completion Basics

The economic success of a well depends in large part on making the optimum connection between the wellbore and the reservoir system. That optimum connection must perform three functions.
1. Let oil into the well, where it can then flow or be pumped to the surface.
2. Keep over- or underlaying water out of the well.
3. Keep the formation out of the well.
Although “completion” has never been universally defined, this concept is its basis. Neither is there universal agreement on the point at which completion begins. Probably the most widely held view is that completion begins when the bit first makes contact with a productive formation. Because formation damage that affects later productivity begins at this point, completions engineers stress the importance of planning wells as the steps that lead to a successful well are complex and interconnected. A multidisciplinary team working cooperatively and interactively can avoid expensive misunderstandings and environmental problems that could result from improperly executed operations. Completion design is a function of numerous reservoir characteristics, such as permeability, porosity, saturation, pressure, stability, and compartmentalization. According to King³, a noted authority on completion, the key to a good initial completion is to collect and assess as much data as possible that are relative to these interrelated characteristics at the earliest possible time.

Porosity and Permeability

Porosity and permeability are the reservoir storage and pathway of flowing fluids. Porosity is the void space between the grains where fluids can be stored. Permeability is a measurement of the ability of fluids to flow through the formation. The higher the permeability, the more easily a fluid can flow through the rock matrix. Most productive formations are between 0.001 and 1,000 md. Porosity does not always relate directly to permeability. Materials, such as shales and some chalks, for example, may have very high porosities but low permeability because they lack effective connection of the pores. When evaluating a reservoir’s economic potential, a porosity or permeability cutoff level often is used to establish minimum pay requirements. This level can be determined from porosity logs and flow tests.

Saturation

In almost every porous formation, there is at least a small amount of water saturation. The remaining fraction of the pore space that contains oil or gas is the hydrocarbon saturation. In general, the most productive parts of a reservoir usually are those with the higher hydrocarbon-saturation values. Water saturation also may be a key determinant of pay because extremely high water saturation could indicate hydrocarbon depletion or movement of an aquifer into the pay. Closely related to porosity and saturation are recoverable hydrocarbon volumes. Not all oil in place can be recovered. The amount of oil that will flow from a rock depends on the size of the pore spaces, the oil saturation and type, and the amount of energy that is available to push the oil toward the wellbore.

Pressure

Reservoir pressure --- the pressure that the reservoir fluids exert on the well at the pay zone --- dictates how much fluid ultimately is recovered. Reservoir pressure varies throughout the productive life of a reservoir. Initial reservoir pressure is the pressure at the time of discovery, but there are other forces involved. These forces, or drives, include solution-gas drive, gas cap, and waterdrive. While many pressure regimes are present and important during the life of a well, pressure differential toward the wellbore is essential for fluid flow during completion and production.

Stability

Reservoir stability can affect the initial completion as well as repairs or recompletions throughout a reservoir’s life. Many geologically young formations lack sufficient strength for formation coherency during all phases of production. These younger rocks often require stabilizing, or sand-control, types of completions to support the formation while allowing it to flow fluids.

Compartmentalization

Compartmentalization is the division of a reservoir into compartments that are partially or fully pressure isolated by faults, permeability or porosity pinchouts, folding, shale streaks, barriers, or other factors. The more that is known about these reservoir characteristics and their interactions with one another, the better the chances of selecting the optimal pay, deciding where to place the wellbore, and establishing the critical link between the wellbore and the formation.³

Types of Completions

There are three primary inflow completion types: natural, stimulated, and sand control. Natural completions are those in which little or no stimulation is required for production. Sandstone and carbonate systems with good permeability and mechanical stability are prime candidates for natural completions. Stimulated completions generally are applied to improve the natural drainage patterns of hard, low-permeability formations or to remove barriers within the formation that prevent easy passage of fluids into the wellbore. Acidizing and hydraulic fracturing are examples of stimulated completions. Sand-control completions are performed in young, unconsolidated or less mechanically competent sandstones to support the formation while allowing it to flow fluids.

Letting Oil In: The First Priority

Originally well completion was thought to mean nothing more than drilling into the pay and letting it 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 a porous formation to a wellbore.⁴ Thus, the concept of creating and stimulating paths of least resistance to the wellbore evolved.

Nitroglycerin Shooting

As early as the 1860s, hard, tight oil sands in Pennsylvania were being shot with gunpowder, then nitroglycerin, to “rubblize” or shatter the rock at the bottom of the wellbore. The practice of shooting explosives increased flow, but the increase was often temporary, and the wellbore was often destroyed. The process was also dangerous. Nonetheless, explosive fracturing continued to be the basic method of stimulating wells until the 1930s.

Early Acidizing

Acid was first used for well stimulation in 1895 by the Ohio Oil Co.⁶ Hydrocloric acid (HCL) was pumped into the microscopic flow channels of limestone formations to dissolve the rock and enlarge the passages.⁷ The treatment was effective, but the well casing was severely corroded. Acidizing declined in popularity until the 1930s, when inhibitors were added to the acid to protect tubulars and treating equipment.

Perforating

Perforating creates a direct link between the wellbore and the producing formation by placing holes through the casing and the cement sheath that surrounds it.
In the early 1900s, mechanical puncturing methods were tried. These included the single-knife casing ripper, which involved a mechanical blade that rotated to puncture a hole in the casing.²

The first perforating mechanism used on a large scale was the bullet gun in 1932.³ In bullet perforating, a hardened-steel bullet is fired from a very short barrel. The resulting perforations cause little damage to the cement sheath and casing, however, the perforation depth is generally short.

Today, shaped-charge, or jet perforating is the accepted industry standard. In this method, a pencil-like jet of gas formed by detonating explosives in a cone-shaped charge penetrates the casing and cement at high velocity and provides clear access to the producing formation.

Modern Perforating

Today, shaped-charge-perforating programs are tailored to completion types and evaluated based on how effectively they accommodate well geometry and reservoir properties. Determining factors for success include the proper differential between reservoir and wellbore pressure and gun selection, which determines shot geometry. Shot geometry is characterized by perforation length and diameter, density (i.e., shots per foot), and phasing (angular separation).

Natural, stimulated, and sand-control completions each have their own perforating requirements. Custom-built guns are often designed for special completion objectives.⁹

Underbalance and Extreme Overbalance

Perforating produces a zone of reduced permeability, referred to as a crushed zone, around the perforation. In the late 1950s, Kruger et al. proved the effectiveness of underbalance perforating (i.e., with the pressure in the wellbore is lower than that in the formation) for removing the crushed zone and improving flow channels.³ Investigation of underbalanced perforating continued for 20 years, then boomed in popularity in the 1970s, when it was tied to innovative designs for tubing-conveyed perforating.

References

Suman, J.R.: Petroleum Production Methods, third edition, Gulf Publishing Co., Houston (1923).
Behrmann, L. et al.: “Quo Vadis, Extreme Overbalance?” Oilfield Review (Autumn 1996) 18.
King, G.: An Introduction to the Basics of Well Completions, Stimulations and Workovers, second edition, George E. King, Tulsa, OK (1996) Chaps. 2 and 3.
Gray, F.: Petroleum Production in Nontechnical Language, second edition, PennWell Publishing Co., Tulsa, OK (1995) 115.
Jeffery, W.H.: Deep Well Drilling, W.H. Jeffery Co., Toledo, Ohio (1921) 323.
Crowe, C. et al.: “Trends in Matrix Acidizing,” Oilfield Review (Oct. 1992) 24.
Bell, W.T. et al.: “Acidizing,” Well Completion and Workover Operations, Completion Technology Center, Houston (1982) 3, Chap. 1.
“Effect of Sand-Filled Perfs on Well Performance,” Oil & Gas J. (19 May 1952) 128.
Cosad, C.:“Choosing a Perforation Strategy,” Oilfield Review (Oct. 1992) 54.