SECTION 2
WELL COMPLETION AND ITS IMPACT ON WATER PRODUCTION

Different types of drilling and completion techniques can affect the amount of water produced during different stages of the life of a well. Further, once the well has been completed and stimulated, remedial actions may be limited. Consequently, at the outset, operators should consider all their options.

Completion Options.  Vertical versus horizontal  Depending on reservoir properties, drive mechanisms and future enhanced oil recovery projects, there can be advantages to one type versus the other. The cost of drilling a horizontal well is more than that of a vertical well; completion costs are also usually higher. Therefore, the volume of salable products must be higher in order to have a higher return on investment (ROI).

The basic benefit of a horizontal well from a reservoir engineering perspective is the generation of a line sink versus a point sink.⁴ This geometry makes more efficient use of reservoir pressure, illustrated by radial flow in the vertical well versus linear flow in the horizontal well. A horizontal well can produce at higher rates than a vertical well at similar drawdown, or can produce similar rates at lower drawdown, thus delaying coning in the case of a bottom-water-drive reservoir.

For a homogeneous reservoir, case histories indicate that reservoirs thinner than 200 feet and having a permeability of less than 100 md should be considered for a horizontal well. For a reservoir with vertical permeability greater than one-fourth its horizontal permeability, a horizontal well might be beneficial. The use of horizontal wells gives another technique to reduce water or gas coning/cresting while producing at higher hydrocarbon rates than can be produced from vertical wells. Case histories have proven that critical oil rates are three to twenty times higher in horizontal wells than in vertical wells.⁵

Heterogeneous reservoirs, such as layered formations and dipping layered formations that can be thick with high permeabilities, and be with or without gas caps and bottom water, can be produced effectively using horizontal wells. However, the heterogeneity has to be defined, the well profile has to be designed to handle the heterogeneity, and the wellbore’s trajectory must be oriented from the geologic information gathered as drilling progresses.

Large production improvements can be realized in heterogeneous reservoirs. Reserves have been increased by as much as factors of 6 in the Austin chalk in South Texas. Partially depleted and flooded reservoirs can be more effectively drained using horizontal wells. In general the production increase of horizontal versus unstimulated vertical wells is proportional to the reservoir’s area contacted by the wells. Due to exposing more of the formation to drilling fluids for longer periods, formation damage may be more pronounced in horizontal wells when problems with drill fluids are encountered.

Open hole versus perforated.  The open hole method is initially cheaper, since perforating costs are eliminated. This method permits testing of the zone as it is drilled, eliminates formation damage by drilling mud and cement, and allows for incremental deepening as necessary to avoid drilling into water. This last factor is important in thin, water-drive pay sections where no more than a few feet of oil zone penetration is desired. On the other hand, the perforated completion offers a much higher degree of control over the pay section, since the interval can be perforated and tested as desired. Individual sections can, in general, be isolated and selectively stimulated much more easily and satisfactorily. There is considerable evidence that hydraulic fracturing is more useful in perforated completions. API Bulletin D6 indicates productivity ratios of perforated wells are about 50% higher than those of similar open hole completions.⁶ This superiority is apparently due to uniform treatment over the entire pay section plus the stimulation benefit gained from penetration of the perforations themselves. The improved zonal control is also of value when remedial measures, such as water or gas exclusion, are undertaken.

With perhaps a few exceptions in low pressure or thin water-drive pay areas, benefits of the perforated completion overshadow those of the open hole type. This advantage has been made possible by modern perforating and stimulation techniques and advances in drilling muds, cementing materials and methods, as well as other aspects of petroleum technology.

Single zone versus commingled.  Most wells are initially completed in a single zone. As production matures and the oil rate declines, other zones may be opened to keep the well economic. Sometimes the initial zone is plugged off prior to recompletion; other times, if it still produces some oil, it is left open or later commingled with other zones. When commingling zones within the same wellbore, consider: 1) compatibility of fluids – mixing different formation fluids tends to increase scale and corrosion problems; 2) reservoir pressure of the different zones – you don’t want one zone to thieve production from another; 3) if unexpected things occur, such as increased water production, it is more difficult and costly to determine which zone is the culprit; and 4) whether the well will ever be used as part of an improved oil recovery project, such as a waterflood.

Other completion options.  Consider all potential production scenarios prior to drilling and completing a well, e.g., the use of downhole oil/water and gas/water separators. This technology, where a well serves as both a producer and an injector, is advancing rapidly and may be more commonly used in the future. Questions to consider prior to drilling: Should the well be drilled deeper to have access to a disposal zone? What size casing should be set to accommodate special tools and equipment?

Stimulation Options.  Natural  completions are when no stimulation is required to achieve commercial production rates or required injection volumes. These are rare, as some type of stimulation is typically required to remove formation damage caused during the drilling process. Natural completions are more common in open hole than cased hole. Potential advantages are no risk of communicating to adjacent formations and more uniform sweep in an injection project.

Acid  is used to remove damage from carbonate and sandstone formations and to stimulate production and injectivity in carbonates. Acid is used for both matrix and fracture treatments in carbonates. Matrix acid candidates have permeability greater than 10 md in oil wells and 1 md in gas wells. Acid frac candidates have permeabilities less than 10 md in oil wells and 1 md in gas wells. Matrix acidizing is performed below the fracturing rate and pressure of the formation, where acid travels through existing pores and natural fractures. Fracture acidizing is performed above the fracturing rate and pressure of the formation, where the rock is cracked and an etched fracture is created.

Matrix acid treatments are commonly used to increase injectivity in disposal and injection wells. Rules of thumb on acid volumes are given in Table 2.⁷

Table 2.  Rules of Thumb on Acid Volumes

 Halliburton’s “Best Practices – Carbonate Matrix Acidizing Treatments,” October 1998.

If acidizing injection and disposal wells is needed on a regular basis to maintain injection rates, water quality should be examined.

Hydraulic fracturing.  When sufficient hydraulic pressure is applied through the wellbore against a particular formation, the formation rock fractures along the plane perpendicular to the direction of the least principal stress. A horizontal fracture will be created if fracture pressure is greater than overburden pressure; a vertical fracture will occur if overburden pressure is greater. The extent of the induced fractures is a function of the pump rate applied after the fracture is initiated.

Hydraulic fracturing is performed to overcome detrimental effects of wellbore damage and/or to stimulate a well’s performance. For the former, it is typically applied to wells in moderate to high permeability reservoirs and generally results in the creation of short fractures. The latter generally results in the creation of long fractures in wells in low permeability reservoirs. The success or failure of fracturing in either case depends on whether the created fracture has significant flow capacity such that reservoir fluids flow to the fracture rather than the wellbore.⁸ If flow capacity of the fracture is large compared to reservoir flow capacity, typically large performance improvements are realized.

Two techniques for improving fracture conductivity are increasing fracture permeability and increasing fracture width. Improving fracture permeability involves methods related to proppant type, proppant concentration, proppant size, and fluid cleanliness. Fracture techniques, such as tip screen-out, are utilized to increase fracture width.

Conventional optimal fracture design is where the pad volume completely leaks off to the formation and the entire created fracture is filled with proppant-laden fluid. If too much pad is pumped, a larger fracture than what is effectively propped is created, which is not cost effective. If too little pad is pumped, a premature treatment termination can result.

When hydraulic fracturing, consideration should be given to potential communication to surrounding zones and whether or not the well might be used in a future enhanced oil recovery project. Fracture treatments can have detrimental effects on the sweep efficiency of a waterflood. Many operators tag the tail end of their proppant with radioactive tracer, so if the well does not respond as anticipated, they can log the well to determine where the fracture went. It is also important to record the initial shut-in pressure behind a frac job, as it provides an estimate for the fracture or parting pressure of the reservoir.

Solid propellant technology. ⁹ Many oil and gas wells can be effectively stimulated with a relatively new gas-generating solid-propellant tool known as The GasGun^TM. The tool incorporates a progressively burning solid propellant that generates gas at a rapid rate, which creates multiple fractures radiating 10 to 100 feet from the wellbore. The progressive burning formulation means that the rate at which the propellant burns increases with time, producing gas faster as the material is consumed. Independent research conducted by Sandia National Laboratories showed this formulation to be much more effective than other propellants in controlling peak pressures and in advancing fractures deep into the formation by saving energy until late in the fracturing process when crack volumes are the greatest.

The fracture network removes damage and increases formation permeability near the wellbore. Potential applications include removing skin and damage, preparing formations for acidizing or hydraulic fracturing, stimulating naturally fractured reservoirs or lenticular sands, increasing injection and withdrawal rates, and improving waterflood efficiency. The process is an economic alternative to hydraulic fracturing and other stimulation methods, especially for treating “tight” zones adjacent to water zones. Various problems associated with hydraulic fracturing, such as breakout or communication to water-bearing zones, are avoided.

Compared to hydraulic fracturing, advantages include much lower cost with minimal onsite equipment needed, little vertical growth out of pay, multiple fractures, entire zone stimulation, and low formation damage from incompatible fluids. Compared to explosives, there is no compaction zone or stress cage produced, pressures last longer for deeper fracture penetration, there is less cleanup, and it is easier and safer to handle.

Tools are wireline conveyed and can be used in open hole or cased wells. Formulations for cased hole application burn somewhat slower, which reduces the peak pressure and generally avoids damaging the casing. To contain the energy, the tool is covered with a 300- to 5,000-foot fluid tamp. Tools are fielded through wireline companies, with services currently available in Illinois, Kansas, Kentucky, Ohio, Oklahoma, and Texas’s Permian Basin.