HORIZONTAL WELLS-6 FORMATION CHARACTERISTICS DICTATE COMPLETION DESIGN

Cameron White
Baker Oil Tools
Houston

Because horizontal drilling is being applied to more and different types of reservoirs, it is becoming apparent that better completion designs are required to optimize production rates, long-term economics, and ultimate producible reserves.

This sixth of an eight-part series discusses the equipment considerations and the benefits of different completion schemes.

COMPLETION DESIGN

Early horizontal completions of fractured carbonate reservoirs consisted mainly of open hole and slotted-liner completions. Initial emphasis was placed primarily on the development of sophisticated equipment required to drill the horizontal well, rather than the refinement of completion technology to produce efficiently from the entire well bore length. An optimum completion design requires thorough preplanning by geoscientists and reservoir, production, and drilling personnel.

In addition to the required hardware, the completion design considerations include such items as well bore location within the reservoir, drive mechanism, future remedial and stimulation requirements, dogleg severity, and horizontal length.

Increased emphasis is being placed on effective and economical zone isolation techniques, especially those which minimize the cost of workover requirements.

No "standard" horizontal completion design exists for horizontal wells, just as there is no standard completion design for conventional wells. Horizontal wells, at least until they become far more routine, will require extensive preplanning and more teamwork between all the disciplines involved.

Both from reservoir and equipment standpoints, there are more things to consider in a horizontal completion design.

There is a considerable amount of completion technology available today which can be applied to horizontal completion problems, and this technology will undoubtedly be expanded and refined over the coming years. Not only will this new technology be useful in horizontal wells, but also in highly deviated long-reach wells and, in some cases, conventional vertical wells.

EQUIPMENT CONSIDERATIONS

Obviously, the major difference in horizontal and conventional completions is the curvature of the well bore, which can range from 1 to 2 ft for an ultra-short-radius well to 3,000 ft for a long-radius well. Wells with a turning radius of less than 300 ft could require special completion and stimulation tools to pass through a severe build-up section of the well bore before entering the horizontal section of the well. For this reason, completion, remedial, and stimulation requirements need to be defined in the early stages of well planning.

As depicted in Fig. 1, the bending stresses introduced into plain pipe increase rapidly as a function of decreasing radius of curvature. Completion equipment is generally more susceptible to damage than the plain pipe considered in these curves.

Fig. 2 illustrates the length of a rigid cylinder that will pass through a radius. As the radius decreases, either shorter or smaller diameter tools must be used. For this reason, short-radius wells are generally limited to either open hole or slotted-liner completions.

Service companies should be consulted on the applicability of specific equipment in specific wells.

Several other physical considerations need to be taken into account when choosing equipment for use in horizontal wells:

Run-in wear. Especially in wells with long horizontal sections and severe doglegs, some standard tools can sustain damage while going into the hole. Centralizers or modifications to the tool may be required.
Gravity. Tail pipe loads below packers or liner hangers can actually go into compression. This could affect the proper operation of completion equipment. Furthermore, tools which rely on gravity to seat balls or tripping plugs cannot be used.
Hydrostatic head. The entire horizontal section is essentially at the same depth and the same hydrostatic pressure. This can lead to well control and fluid loss problems during completion and stimulation operations when the reservoir pressure varies along the length of the well bore. This has caused problems in some West Texas and North Sea completions.
Hole roundness and caliper. Generally, the build and horizontal sections will not be round, and the hole size will be larger than the bit size. This can adversely affect the performance of inflatable packers set in these sections of the hole.
Liner tops. If completion or stimulation assemblies are run through liner tops at high angles, special precautions are needed in designing the liner top and in selecting equipment that will run through the top.
Solids on the bottom of the hole. Of particular importance are cleaning the hole prior to running a liner and providing a means to circulate to bottom and rotate the liner if problems are anticipated. Also important is to minimize the amount of debris inside the horizontal portion of completions.
Debris accumulates if there is difficulty in obtaining sufficient fluid velocity to circulate it out. This is especially important if flow control devices, such as sliding sleeves, blanking plugs, etc., are used in the horizontal section.
Avoid measured rotation and reciprocation. Torque and drag in horizontal holes can complicate the operation of some standard completion and stimulation assemblies. If such tools are used, they should be of a type that gives a positive surface indication when a function has been performed. Tools are available with positive stops that do not depend on precise string movements at the tool.
Use hydraulically operated tools. Numerous hydraulically operated tools are available which are preferable to mechanically operated tools in horizontal applications. Generally, the operation of these tools is not affected by being in the horizontal portion of the well bore.
Coiled tubing replaces wire line. Conventional wire line equipment cannot be run beyond an angle of 65-70; therefore, coiled tubing is being widely used to perform many of the operations normally done with wire line. In addition to the traditional use of conveying fluids downhole, coiled tubing is now being used for data acquisition, remedial and stimulation operations, setting and retrieving plugs, and operating flow control equipment.

HORIZONTAL COMPLETION TYPES

As discussed in previous literature, two basic types of horizontal completions exist: the continuous entry and the discreet flow entry.1-3 Open hole and slotted-liner completions fall into the category of continuous flow entry completions and are characterized by the fact that they offer little or no provisions for zone isolation.

Open hole packer completions bridge the gap between continuous and discreet flow entry by allowing large segments of the entering flow to commingle, yet the well is segmented into more manageable increments which can be treated separately.

Discreet entry completions are typified by cemented and perforated liners (or production casing) and offer many completion, remedial, and stimulation options.

OPEN HOLE

Open hole completions obviously involve the least initial expense of the completion types under consideration here. An open hole completion is limited to very competent formations where little or no zone isolation requirement exists.

These completions are most commonly used in competent fractured limestone or chalk formations, such as the Austin chalk in Texas and the Rospo Mare field offshore Italy.4 In short-radius horizontal wells, open hole completions are also quite popular.

Besides saving the cost of the liner and cementing, the open hole completion can minimize the damage to the formation by eliminating cement that may cause plugging of the fracture face and significantly decrease productivity.

The option also exists for recompletion of the well if zone isolation is required later in the life of the well, provided the hole does not collapse or fill with produced solids. Temporary zone isolation techniques in open hole completions are generally limited to the use of retrievable inflatable packers. Numerous configurations and sizes of inflatable packers are available for use in horizontal open hole completions.

Inflatable packers can conform and seal in out-of-round and irregular well bores (within limits defined by the manufacturer). Because these packers are hydraulically operated, they are particularly suitable for use in horizontal open holes.

Inflatable packers, permanent bridge plugs, retrievable bridge plugs, cement retainers, and straddle assemblies are available for a wide range of well testing and production control applications.

Coiled-tubing-conveyed inflatable packers and bridge plugs have recently become available. These allow small diameter packers to be run through the production tubing and completion assemblies and set in the open hole or casing below, thereby eliminating the need to pull the completion (Fig. 3).

Retrievable inflatable packers in open hole have several limitations. First, they generally have lower pressure and temperature limitations than conventional packers set in casing. The differential pressure holding capability is a function of hole size and temperature. In addition, the pressure across the packer could be limited by the formation in which the packer is set.

The formation could conceivably fail before the packer, or in a high permeability formation, high pressure fluid may bypass the packer. These factors need to be considered when planning open hole remedial and stimulation jobs. Typical operations performed with inflatable packers in horizontal open holes are production testing, moderate-pressure acid treatments, water and gas shutoff, shutoff of depleted fracture systems, and cement squeezes.

SLOTTED LINER

Slotted (or preperforated) liner completions are by far the most common completion run in horizontal wells.5 The primary purpose of the slotted liner is preventing hole collapse in formations that may tend to cave in after being drilled, or as the formation pressure depletes.

Slotted liners may be hung from liner hangers or production packers. In some cases, the upper portion of the liner through the build section may be cemented to seal off a gas cap or problem zone above the payzone (Fig. 4a).

If anticipated hole conditions will make it difficult to get the liner to bottom because of inadequate hole cleaning or tight spots, an assembly, such as the one shown in Fig. 4b, may be used to facilitate running the slotted liner to bottom.

A feature is provided in the production packer (either retrievable or permanent) to rotationally lock the run-in string to the packer and the packer to the slotted liner. This enables the liner to be rotated through tight spots.

The wash pipe extending below the running tool to the drillable pack-off bushing enables circulating to bottom the slotted liner. Circulation is possible through fill or bridges in the hole.

After the packer is set, the running tool and wash pipe are retrieved. This allows the flapper in the pack-off bushing to close, which prevents the entry of large solids through the guide shoe.

Because typical slot widths are in the range of 0.020 in., slotted liners are not particularly effective at excluding the production of formation sand that typically has a median grain size in the range of 0.004 in.6 Wire-wrapped screens, prepacked liners, or gravel packing are preferred alternatives when sand control is a potential problem.

Slotted liner popularity is due primarily to its extensive use in the numerous horizontal wells drilled in the Austin chalk and Bakken shale formations. Here, zone isolation has not historically been a great concern of operators. It is important to note that these formations do not exhibit water or gas coning problems.

The primary disadvantage of slotted liner completions is the fact that there is no known method of effectively isolating zones or sections of the well bore. Consequently, production logging, production control, and remedial options are severely limited.

The use of slotted liners should be limited to applications where it is recognized that zone isolation will not be required, and the formation strength is believed to be inadequate to prevent cave-in or collapse of the well bore.

Operators in various parts of the world have experienced problems such as gas and water breakthrough, loss of production to depleted fracture systems, and the need to stimulate selected portions of the well bore. These problems could not be remedied because of the limitations of a slotted liner.

In such cases, operators have changed completion design on subsequent wells and have gone to either open hole or have added external casing packers (ECPs) to allow some degree of zone isolation and selectivity.

OPEN HOLE PACKER

The open hole packer completion, which in various forms has been used in conventional wells for many years, is being utilized extensively in horizontal wells where zone isolation is required, but cementing of the liner through the horizontal section is either impractical or uneconomical.

These formations include zones with lost circulation such as in a naturally fractured carbonate formation. Inflatable formation packers, for instance, have been proven effective in achieving zone isolation in horizontal holes in Alaska.

There are several variations of the open hole packer completion (Fig. 5), but all utilize some type of inflatable external casing packer in the uncemented annulus to break the well bore into shorter, more manageable increments that can be dealt with individually.

The simplest type of open hole packer completion is the ECP with slotted liner. This is similar to the slotted liner completion, but inflatable ECPs are spaced out along the length of the payzone.

Depicted in Fig. 6a is a completion designed for a fractured limestone formation with an active water drive mechanism. This was to be the first horizontal well in this particular field; therefore, accurate production logging results were required to quantify the production from each of the four segments of the well bore. In anticipation of premature water breakthrough, one of the requirements was that any one or combination of zones could be shutoff. Fig. 6b shows a straddle-packer assembly which could be run to shutoff production from Zone B.

A drawback of the ECP with slotted liner is that many of the anticipated production control, testing, and stimulation operations must be done either before the production tubing and packer are run, or the production tubing and packer in the vertical or build section of the hole must be removed. Another type of open hole packer completion is the ECP with sliding sleeve as shown in Fig. 6c.

The ECP with sliding sleeve was first run in a horizontal hole in a 2,000-ft lateral gas well in Wayne county, W.Va.7 8 In this particular completion program, 4 1/2-in. casing with external casing packers and port collars was installed. The completion string was installed in 2,000 ft of open hole that had been air drilled.

In the design of the casing string, both geophysical well logs and a borehole television camera survey were utilized so that the shale intervals could be isolated for testing and evaluation prior to and following stimulation.

Similarly, the ECP with sliding-sleeve-type completion was also run in the Austin chalk9 and has been proposed for horizontal wells in Alaska.10 This type of liner-mounted completion should not be used where hole collapse is anticipated, since fluid entry occurs only at each sliding sleeve. This is opposed to a slotted liner where fluid entry is continuous over the length of the slotted liner. Hole collapse could prevent flow through the annulus to the sliding sleeve.

The ECP with sliding sleeve is applicable where faults, fractures, and high permeability streaks need to be isolated. Additionally, it can be used to shutoff a zone which shows premature water breakthrough. With this or any other type of completion it may be difficult to shutoff gas breakthrough if reservoir pressure drawdowns are high.

The ECP with sliding-sleeve-completion technique has been applied to shale, fractured carbonate, and competent sandstone formations. It is particularly cost effective in areas where workover rig and recompletion costs are high, such as offshore and remote areas.

Selectivity is achieved by using coiled tubing or work-string-conveyed shifting tools to open and close the sleeves during various testing, stimulation, and production control operations. Specialized shifting tools have been developed and are continually being refined for shifting sliding sleeves in horizontal wells (Fig. 7).

Rotational port collars have also been used in this application, but sliding sleeves are preferred since they are better suited to production applications and can be manipulated more easily with coiled tubing.

There are several types of inflatable ECPs used in the open hole packer completions. ECPs are available from 3 to 40 ft lengths and can be inflated with either fluid or cement. The choice of packer type and inflation medium depends on the particular application, well geometry, and formation type, but generally the ECPs with 10-20 ft long sealing elements are preferred in horizontal applications. To a large extent, successful zone isolation depends on the formation in which ECPs are set. If installed in a highly permeable formation, the ECP may be successful in achieving some degree of zone isolation, but will not be as effective as a cemented liner.

In relatively impermeable formations, especially those where production is from fractured systems, ECPs can provide more effective zone isolation. Furthermore, some operators have taken advantage of productive zones, such as impermeable shale lenses, in which to set the ECP. This technique, when practical, should greatly increase the effectiveness of the ECP in isolating zones.

CEMENTED LINER

Where requirements dictate the need for positive zone isolation and the maximum number of options for long-term reservoir management, the cemented liner completion offers a better solution than previously discussed techniques. These requirements may include, among other things, high-pressure stimulation and precise production or injection control.

Although cementing and perforating are more expensive and can cause formation damage and restrict production rates in some types of formations, the advantages must be weighed against these disadvantages.

It has been well documented that with proper planning, equipment, and execution, cementing horizontal wells can provide excellent zone isolation that can withstand the massive multiple-zone hydraulic fracturing jobs which have been done in the North Sea.11-13 Furthermore, successful cementing has proven effective in providing zone isolation in Norman Wells, Canada.

When a well is cemented and perforated, production logging, production control, injection control, and a wide variety of remedial and stimulation options are available. Equipment is now available, and new equipment and techniques are being developed, to perform most of the required operations. A wide variety of completion designs have been run or proposed that take advantage of zone isolation and discreet fluid entry points provided by this type of completion.

The simplest design is to cement and perforate the liner and run a relatively standard production packer above the horizontal section. This allows selective perforations that produce only from desired sections of the well bore while offering several options for future operations.

Conversely, with a cemented liner the production string, packer, nipple profiles, etc. restrict the size of the tools which can be run into the horizontal section without first pulling the tubing and packer. However, many tools have been developed which can be run on coiled tubing to perform a variety of tasks without the need to pull the completion.14 15

For example, coiled-tubing-conveyed packers, bridge plugs, and straddle assemblies can be used for various testing, remedial, and zone abandonment operations. If more extensive work is required, the tubing and packer can be removed for full Workover operations.

A modification of the cemented liner completion has been run in the North Sea in an extended-reach well with a relatively high production rate, and is planned for future horizontal wells. This monobore completion utilizes a 7-in. or 6 5/8-in. liner with a 7-in. production tubing string and large bore permanent packer.

The restrictions on the production string are minimal, and a variety of conventional bridge plugs and straddle assemblies can be run through the production string to shutoff zones where premature water breakthrough occurs. Similar completions have been run with 5-in. tubing and liners.

This monobore approach is most applicable in high-permeability sandstone reservoirs with a large productivity index and water or gas drive. In such reservoirs, analytical methods have been presented16 which show turbulent flow, and a resulting increase in flow resistance along the hole can cause the incremental production to drop off significantly as the operator moves away from the first set of perforations along the well bore.

The resulting increased drawdown at the upper end of the well can cause premature water or gas coning, which may need to be regulated or shutoff. It is important to note that this phenomenon is aggravated by smaller tubular sizes. Therefore, it is desirable to provide minimal flow restrictions and as large a tubular size as practical through the horizontal section.

The completion shown in Fig. 8 was developed in conjunction with a North Sea operator for a tight carbonate formation requiring multiple hydraulic fracture treatments.10 The completion system was designed for long-radius horizontal wells with fully cemented 7-in. liners.

After completion, selective production, testing, and treating can be accomplished by the use of coiled-tubing-conveyed equipment without removing the production tubing and packers. This was especially important in portions of the reservoir underlying a gas cap because it was felt the gas first would break through sections where the drawdown was higher. It was highly desirable to shutoff these zones without killing the well and doing a complete workover.

Along with the downhole equipment developed for this particular system, a string of coiled-tubing-conveyed tools was developed to wash debris, shift sliding sleeves, and retrieve blanking plugs in the horizontal section. Other tools will soon be available to set and retrieve plugs, blanking sleeves, flow regulators, and pressure-gauge hangers in horizontal wells.

Major objectives of the cemented-liner completion design were to reduce or eliminate the loss of completion fluids to the formation after fracturing each zone and to reduce the time required to stimulate and complete the well. To date, six wells (approximately 50 zones) have been successfully completed utilizing slightly different variations of the cemented liner completion.

Cemented-liner completions have been designed for a variety of horizontal well applications. Dual completions, completions with flow regulators between zones, and multiple-fracture wells in fluid-sensitive gas sands have all been designed or proposed for horizontal wells. The common requirement in all of these cemented-liner completions is the need for positive zone isolation.

REFERENCES

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