HORIZONTAL GAS-STORAGE WELLS CAN INCREASE DELIVERABILITY

Oct. 11, 1993
Fred J. Pittard, Jim A. Madigan SlimDril International Inc. Houston Horizontal drilling with special attention to the requirements of gas-storage zones can yield wells with deliverability about six times that of comparable vertical wells. Although horizontal-drilling technology used on development wells can be successfully applied to gas storage, there are several major differences that must be considered during both planning and drilling.
Fred J. Pittard, Jim A. Madigan
SlimDril International Inc.
Houston

Horizontal drilling with special attention to the requirements of gas-storage zones can yield wells with deliverability about six times that of comparable vertical wells.

Although horizontal-drilling technology used on development wells can be successfully applied to gas storage, there are several major differences that must be considered during both planning and drilling.

Special areas of attention include reservoir evaluation, formation characteristics along the well path, target objectives, and well design. The well planning includes well location and target, hole size, tubular program, well path, radius, and horizontal objectives.

These factors directly affect the bottom hole assembly (BHA) configuration, drillstring components, casing program, and drilling-fluids program. Consideration of these drilling factors during well planning can minimize the time required to complete the project and reduce risk.

Contingency plans for each phase must be prepared and ready. Additionally, constant open communication between all participating parties is essential for success. Reservoir analysis, prespud planning, and a team approach to drilling engineering involving both operator and contractor are keys to a successful project.

GAS-STORAGE WELLS

Thousands of horizontal oil and gas producing wells have been drilled, yet only a few successful horizontal gas-storage wells have been brought on-line.

Horizontal wells typically cost about twice as much as comparable vertical storage wells to drill and complete, yet their deliverability is significantly greater. Thus, drilling one new horizontal well could be potentially more cost effective than drilling a number of vertical wells or working over several older wells to achieve a similar increase in deliverability.

Horizontal wells typically operate with lower pressure gradients than their vertical counterparts. The lower gradient is important because less water is produced and less sand is delivered to the well bore. Theoretically, therefore, horizontal wells should have a greater useful life before a workover is required.

Because the horizontal storage wells operate at lower pressures, less base or cushion gas must remain in the horizontal storage well to maintain minimum production, making the wells more efficient than vertical wells. A field development plan using horizontal wells can call for fewer wells, requiring less capital than vertical wells. Also, operating and maintenance costs are lower because of fewer wells.

PLANNING

In the planning and drilling stages of a horizontal well, several factors require more attention for gas-storage wells than for typical oil and gas producing wells:

  • Expected life of the well

  • Production rates and repressurization cycles

  • Narrow formation targets

  • Low pore pressure and formation damage potential

  • Differential sticking of drill pipe.

Gas-storage wells are a long-term investment--40 years or more of well life is not uncommon. The well design must therefore address this expected life.

By comparison, the life of a common horizontal oil well in the Austin chalk, Sprayberry, Permian basin, or Niobrara areas may range 4-15 years.

The horizontal storage-well completion must handle a high level of gas production, which varies with peak requirements, and also the injection process, which may consist of several cycles per year.

A major difference between an Austin chalk, Niobrara, or Permian basin horizontal well and a typical gas-storage well is the size of the target zone. Typically, an Austin chalk horizontal well may have a 30-60 ft target window, whereas a potential gas-storage formation will have a 10-25 ft target window. The smaller target requires greater directional control and accuracy.

An oil well with a large target may be drilled with a high rate of penetration by rotating the drill pipe and the downhole motor simultaneously. Measurement-while-drilling (MWD) directional measurements may be taken at intervals for acceptable accuracy.

A gas-storage well, in contrast, may have to be drilled solely by slide drilling (no rotation of the drill pipe) using only the power of the downhole motor. Using a hard-wire MWD, directional measurements are taken continuously while slide drilling for high accuracy.

The high permeability and low pore pressure in gas-storage zones presents increased risk of formation damage. Thus, to avoid formation damage, these wells should be drilled near balance but within a projected safety margin because a well in an active field is likely to produce gas.

The mud systems must be carefully selected because the low pore pressures contribute to differential sticking problems.

Although completion and logging techniques are different than those used in vertical storage wells, methods are readily adaptable from standard horizontal production wells. The logging tools can be conveyed on coiled tubing, or pump-down wire line tools can be used if the pump-down fluid will not cause formation damage.

Most of the storage wells drilled to date have been completed open hole in consolidated formations. For less consolidated formations, slotted liners may be necessary. Because an increasing number of horizontal producing wells are being drilled in formations other than chalk, completion technology is advancing rapidly, and many of the techniques are applicable to gas-storage wells.

Horizontal wells are drilled with a short radius (25-200 ft), a medium radius (200-500 ft), or a long radius (500 ft). Short radius horizontal drilling is beneficial in gas storage because the well can reach target zones under a cap rock. Medium-radius techniques might require drilling through the cap rock and then casing it off.

With current technology, a drilling radius as short as 75 ft can be used with a fully steerable hard-wire MWD system. The benefits of short-radius horizontal drilling include the following:

  • Reaching shallow objectives

  • Remaining under cap rock and above wet zones

  • Reaching near well bore targets

  • Drilling less footage before the horizontal zone is reached

  • Allowing optimum well placement in a field.

RESERVOIR MODELING

Reservoir modeling has contributed significantly to the successful application of horizontal drilling to gas-storage operations,

Current computer software can model reservoirs extensively to improve the evaluation of planned horizontal storage wells. Capacity, deliverability, injection volume, cushion gas, and other factors can be determined with relative ease.

Cap rock integrity, formation characteristics, and geological features require careful scrutiny. The criteria affecting performance include horizontal and vertical permeability, water contacts, impermeable barriers, overall reservoir size, formation layering, homogeneity, and porosity.

Fortunately, a great deal of research has gone into horizontal well modeling, producing accurate simulation models. These models draw on reservoir characteristics and data from vertical wells.

Some of the more significant input information include the following:

  • Total pore volume

  • Formation thickness and fracture conductivity

  • Well bore pressure

  • Permeability, porosity, and skin factors

  • Base gas and working gas

  • Peak deliverability

  • Cyclic performance, temperature, and pressure

  • Well history, location, and depth

  • Original pressure and production data.

The models can help in the study of a variety of scenarios based on different well location, radius, length, and direction of extension.

Teamwork between operator and directional-drilling contractor in the planning stages is critical because the final well path optimized from a reservoir standpoint must also be physically drillable with minimum risk.

Optimizing the well path early in the planning stages should incorporate torque, drag, hydraulics, mud programs, and other pertinent drilling factors. Once alternative scenarios are evaluated together with drilling considerations, the most cost effective and lowest risk plan can be determined.

RE-ENTRIES

An existing vertical well with casing and cement in good condition may offer an opportunity for savings on the planned horizontal well. The vertical well is re-entered and a window or section is cut in the original casing. The horizontal extension is drilled from this point.

A new well, however, may be planned without any of the existing well restrictions. Fig. 1 shows a typical casing program.

The present field condition, stage of development, condition of the tubulars, surface equipment, production limitations, economics, and well spacing determine whether a re-entry may be more feasible than a new well.

Offset drilling and logging data are also useful in esti- mating the degree of difficulty involved with a re-entry. These offset wells used for comparison should be in the same section, township, and range.

Re-entry costs vary with the complexity of the project, but savings of 20% to 40% may be possible compared to the cost to drill a new well. For the re-entry, existing leases are used, locations are already prepared, and flow lines are in place.

Savings increase with increasing well depth because the entire vertical section does not have to be drilled nor casing run and cemented.

Offsetting these pluses, however, are the costs associated with evaluating the condition of the casing and cement bond, setting a packer or cement plug below the kick-off point, and section milling or window cutting (Fig. 2).

In a re-entry, the desired radius of curvature may be restricted because of casing size limitations, and horizontal extensions may be smaller in diameter than optimum.

The popularity of cased well bore re-entry wells, however, indicates that this option deserves ample consideration if a candidate well is available.

WELL COMPLETION

The casing and tubing program must take into account the estimated gas production and injection as well as any geolgical constraints for zone isolation.

After the formation characteristics are evaluated, a cementing program must be designed carefully to prevent gas migration from the storage formation. The producing formation must be thoroughly sealed from the formations above, and wet zones below must be avoided.

If the well is a re-entry, the condition of existing casing and cement bonds must be evaluated thoroughly.

The pressure losses through downhole equipment, liners, surface equipment, and flow lines must be calculated to ensure the well can deliver at planned peak flow rates. Furthermore, the selected completion equipment must be evaluated in the context of the planned well bore.

Torque and drag on the completion string are typically calculated with sophisticated computer programs to ensure that the stress limits of the equipment are not exceeded. The radius of curvature, hole size, and length of horizontal extension are then modified as necessary to accommodate the completion equipment plan within acceptable torque and drag limits.

DRILLING ENGINEERING

Several geologic factors must be considered in the planning stages. A thorough review of offset well logs is necessary to verify formation tops, markers, and caps.

Also, a thorough review of offset bit and drilling records is necessary to correlate geology and formation changes, mud systems, bit types, hydraulics, and drilling conditions.

Ideally, logs and drilling records from wells in the same field should be evaluated. From a drilling perspective, gamma ray and spontaneous potential (SP) logs are the most useful to select the BHA, motor, and bit type because theses logs provide information on formation type and ability to be drilled.

If no logs are available from the immediate area, then geology is necessarily correlated to the closest wells, taking into account faults and updips that can affect correlation.

Determination of formation type, porosity, and susceptibility to swelling and careful examination of daily drilling logs provide important information for estimating the days required to drill the well.

BHA SELECTION

The typical BHA consists of the bit, a positive-displacement motor (PDM) with a bent housing, nonmagnetic drill collars that house the MWD unit, and an orienting and circulating sub attached to the drillstring.

BHAs for medium-radius drilling differ somewhat from those used in short-radius projects (Fig. 3).

The medium-radius system typically uses a standard steering tool or MWD instead of the high deviation steering tool, and the motor housing may only have one bend instead of two. Both types are fully steerable throughout the entire lateral section.

BIT SELECTION

Correct bit selection can mean the difference between a successful and unsuccessful well both from a drilling and an economic standpoint. Careful bit and drilling record evaluation of offset wells is essential. Additionally, the operator should consult with other operators who have drilled in or near the same field.

A high rate of penetration should not be a primary concern while the radius section is drilled. The radius should be drilled as accurately and as smoothly as possible to minimize doglegs and to achieve casino point inclinations and true vertical depth (TVD) targets.

Bit selection should take into consideration the following points:

  • Directional control

  • Torque and vibration

  • Projected bit life

  • Expected penetration rate

  • Planned minimum cost per foot.

Several types of drilling bits are used in drilling horizontal gas-storage wells. The fixed cutter-type bits used are thermally stable diamond bits, natural diamond bits, and polycrystalline diamond compact bits. Roller cone mill tooth and tungsten carbide insert bits have also been used successfully.

Generally, in small-diameter well bores (4 3/4 in. and smaller) fixed cutter bits are preferred because bearing systems on small diameter rolling cutter bits typically deliver a short operating life.

At times, a combination of fixed cutter and roller cone bits are used in a well, particularly when a large-diameter radius is drilled, and a small-diameter horizontal section is drilled after the casing is run in the radius section.

Bit selection ultimately depends upon downhole motor type, drilling economics, hydraulics, and geology. Usually, more than one type of bit is available on location to handle contingencies during the drilling operation.

DOWNHOLE MOTOR

A PDM based on the Moineau principle can be designed to provide various combinations of torque and rotational speed. Drilling fluid pumped down the string drives the rotor, which rotates inside the stator.

The speed and torque of a PDM motor are proportional to the pressure drop across the motor and the amount of fluid pumped through it. Increased weight on bit causes increased reactive torque and higher pressure drop across the motor.

The directional driller can control flow rate and weight on bit to optimize operating parameters. Motors are often designed to deliver one of the following:

  • High rotational speed at low torque

  • Medium rotational speed at medium torque

  • Low rotational speed at high torque.

High speed low-torque motors are typically a 1:2 lobe (rotor:stator) design. Low speed high-torque motors are multi-lobe design, with the most common being either 4:5 or 5:6 designs.

Angle building during drilling of the radius is accomplished by use of a motor with a bend. In the horizontal section, a motor with only a slight bend is used. The motor is oriented to stay within the target by the drill pipe being adjusted from the surface.

The selection of the proper PDM depends on geology type, hydraulic capacities, desired build rate, and occasionally, hole size.

A contingency plan should be used for varying BHA build rates because of geological conditions.

For example, if the well is designed with a 16/100-ft build rate for the radius and the geology or hole conditions result in a 12/100-ft build rate, a contingency plan for correcting the 12/100-ft build rate must be available.

The change in build-up rate may be achieved through a BHA configuration change using higher angle bends or through a drilling course change.

MWD TOOLS

The surveying system for the steerable BHA will include either a hard-wire MWD tool in combination with a wet-connect system or a mud pulse MWD unit. The systems use identical electronics for directional measurement.

The hard-wire system has certain advantages:

  • Lower cost

  • Wire line retrievable in small diameter tubing

  • Higher data-transmission rates

  • Higher temperature capability

  • Ability to transmit continuously in the sliding mode for higher accuracy

  • Ability to operate during lost circulation

  • No battery packs.

On the other hand, the mud pulse MWD unit does not require a wire line system because it sends signals directly through the drilling fluid when drilling is stopped.

Both systems provide real-time measurement and feedback, including inclination, azimuth, and tool-face orientation (Fig. 4).

MWD instrumentation is placed in nonmagnetic drill collars directly above the PDM.

A wet-connect system is used with the hard-wire MWD unit to allow the wire line to remain in the hole during rotary drilling. This system allows rotary drilling to continue without removal of the wire line and steering tools.

The hard-wire MWD wet-connect system is operable in small diameter holes as well as large-diameter holes. A special flexible assembly is used for short radius projects (Fig. 5).

ORIENTING SUB

An orienting and circulating sub is typically placed in the drillstring between the downhole motor and nonmagnetic drill collars. This sub orients the tool face of the bit to an exact position relative to the drill pipe. Thus, tool-face orientation is always known exactly.

The sub also allows fluid to bypass the motor if circulation for hole conditioning or other reasons is required. The sub also allows fluid to drain from the drillstring during tripping, so that a wet string does not have to be pulled from the hole.

DRILLSTRING

Several factors must be taken into account when selecting the proper drillstring for horizontal wells:

  • Ability to provide maximum weight to bit

  • Hydraulic capacity

  • Resistance to buckling and deformation

  • Passage of survey equipment

  • Ability to be fished.

A typical drillstring program for a small-diameter, short-radius well has tubing above the BHA long enough to travel through the entire radius and the horizontal section to be drilled. Above the tubing, heavyweight drill pipe or drill collars are used to deliver weight to the bit through the tubing.

The tubing, often CS-Hydril, PH-6, or a similar type, is highly flexible and can accommodate a short radius without permanent deformation.

The drillstring design must be evaluated carefully along the exact projected well path to avoid buckling. Computer models are first used to construct the well path. Then, the expected torque, drag, buckling, and differential sticking are analyzed, and the drillstring design is modified, if necessary.

CASING PROGRAM

The casing program for a horizontal gas-storage well must be carefully designed; the major casing and cementing program objective is to achieve a durable seal at the cap rock.

The strength of the casing must also be compatible with the rate of curvature of the radius. All tool joints must hold a seal with no fatiguing while under stress in the radius.

In practice, it is advisable to ream the radius section after it has been drilled to eliminate any ledges or severe doglegs. The casing is easier to run after the well bore has been reamed, and reaming also helps provide a better cement bond.

Additionally, proper cement hardware must be used in the casing program. The use of premium hardware is advisable considering the extended life and difficult operating requirements of a horizontal gas-storage well.

DRILLING FLUIDS

The drilling fluids program must be designed to protect the storage media by minimizing skin damage, thereby ensuring optimum deliverability and injection. A fluid/rock compatibility study and consultation with a drilling fluids specialist are recommended.

Gas-storage drilling often involves a high-permeability, high-porosity sand. Thus, the tendency to encounter fluid loss and skin damage is high.

Drilling ahead in a live well, although fairly common, still must be considered in designing the fluids program. A fluid that performs well in a well-control situation must be available (and compatible with the formation) if pressure is anticipated while drilling.

Separate fluid programs may be needed for the radius and lateral sections. If distinct different formation types are present in the radius and lateral sections, individual fluid programs may be mandatory.

The effect of differential pressure on pipe drag is significant in porous formations. The force required to free stuck pipe is proportional to the area subjected to differential pressure. The area subjected to differential pressure can be large if the stuck section is in the horizontal portion of the well.

Also, because of additional annular pressure drops, more differential pressure is created. Once the pipe is differentially stuck, it is extremely difficult to move the drillstring, if it can be moved at all. One solution to combat this problem is the use of glass beads and oil based drilling fluids.

The potential problem should be recognized during contingency planning with suitable responses prepared before drilling begins.

Well control is a critical issue in horizontal gas storage because the formations are shallow and the zones may be live. In shallow gas fields, a gas bubble can reach the surface in a short time. The balance between well control and pressure gradients because of equivalent circulating densities must be reviewed. The longer horizontal section will increase annular pressure drop.

ACKNOWLEDGMENT

The authors would like to thank SlimDril International Inc., Oklahoma Natural Gas Co., ANR Pipeline Co., ANR Storage Co., Drilling Research Center, Maurer Engineering Inc., and the Gas Research Institute for information used in the preparation of this article.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.