HORIZONTAL DRILLING USED IN GAS STORAGE PROGRAMS

April 5, 1993
Farrile S. Young Jr., William J. McDonald Maurer Engineering Inc. Houston Yusuf A. Shikari Gas Research Institute Chicago Horizontal wells may restore deliverability in old reservoirs and help efficiently develop new, porous-media, natural gas storage reservoirs. In many types of gas storage reservoirs, horizontal wells can have 5-10 times the productivity of vertical wells yet cost only about twice as much.
Farrile S. Young Jr., William J. McDonald
Maurer Engineering Inc.
Houston
Yusuf A. Shikari
Gas Research Institute
Chicago

Horizontal wells may restore deliverability in old reservoirs and help efficiently develop new, porous-media, natural gas storage reservoirs.

In many types of gas storage reservoirs, horizontal wells can have 5-10 times the productivity of vertical wells yet cost only about twice as much.

The advantages of using horizontal wells in gas storage include the ability to develop less-favorable parts of the reservoir, fewer surface sites, less pipe and surface equipment, improved late season deliverability at low pressure, and reduced base gas requirements.

A comprehensive analysis of more than 85% of U.S. gas storage reservoirs found an average annual productivity decline of about 5%. The gas storage industry spends more than $100 million annually on remedial operations to reduce this decline and maintain deliverability.

Since 1990, the Gas Research Institute (GRI) has sponsored a project to increase the deliverability of the nation's 14,000 gas storage wells. The primary objective of the study is to conduct a comprehensive review of deliverability enhancement techniques, well completion methods, and procedures used by operators of underground natural gas storage fields in North America. Another objective is to design and construct a computer data base and compile reports and analyses in aggregated format.

The first task of the project involved an assessment of the state of technology. Data on the location and characteristics of storage fields were gathered with cooperation from the American Gas Association Operating Section Underground Storage Committee. This information was reviewed and up-dated by the operators. A dbase IV data base was developed to store the data.

Additional technical and operational data came from personal interviews with 15 gas storage companies and several oil field service companies. These gas storage field operators were selected to represent a cross section of all operators, and each owned or operated fields which might benefit from the development of improved deliverability enhancement techniques. Management, engineering, and field operations personnel were interviewed about deliverability problems and procedures to combat decline. The interviews focused on four principal areas:

  • Storage field development and operating methods, including economic analyses and environmental and institutional problems

  • Field testing used to assess deliverability enhancement

  • Cost and effectiveness of enhancement techniques

  • Assessment of need for improved technology.

Personal interviews, mailed surveys, and a literature search of gas storage and conventional exploration and production technology were used to help define the current technology of deliverability enhancement for gas storage wells.

GAS STORAGE SURVEY

All known gas storage operators and fields were included in the survey (Table 1). The gas storage reservoir data in the data base were classified according to lithology, reservoir structure, and reservoir driving mechanism. A 2 x 3 x 2 matrix defines 12 types (R1-R12) of gas storage reservoirs (Fig. 1). Salt domes were classified in a separate category.

Table 2 lists the average properties of each type of reservoir. Table 3 shows the deliverability decline rate for each reservoir classification.

The deliverability loss for all reservoirs was calculated as 5.2%/year (the reported decline for each reservoir classification was converted to MMscfd, summed, and then divided by the total reported deliverability).

Approximately 25% of all classified reservoirs have deliverability decline problems, and the prevalence of deliverability problems varies across the classifications. The operators of about half of the R3, R4, and R9 reservoirs reported problems with deliverability. Sixty-eight percent of the operators identified formation plugging as a predominant cause of storage well deliverability decline.

The nine following methods of well deliverability restoration or enhancement are the most widely used:

  • Acidizing

  • Blowing

  • Fracturing

  • Gravel packing

  • Infill drilling

  • Mechanical cleaning

  • Reperforating

  • Replacing tubing and packer

  • Washing.

Acidizing, washing, reperforating, and infill drilling constitute nearly 84% of the survey responses. Infill drilling, however, is often used for reasons (such as well replacement because of mechanical failure) other than deliverability restoration.

Table 4 ranks the effectiveness of these enhancement techniques for each reservoir classification based on lithology, trap type, and reservoir drive. Table 5 is a summary of industry-wide activity and costs based on an analysis of the survey data. More than $100 million/year is spent in the gas storage industry to replace losses because of permeability impairment. Washing, acidizing, and infill drilling account for more than 95% of the annual spending on enhancement operations.

The annual decline in natural gas storage deliverability is significant (more than 3 bcfd/year). The primary cause of the decline is the skin effect along the well bore. Extension of the well bore beyond the skin is necessary to recover lost deliverability.

Horizontal well technology is a promising method which can increase peak deliverability by 300-700% at low pressure (late season), reduce base gas, and improve efficiency by reducing capital and operating expenditures. Horizontal drilling has been successfully used to increase productivity in conventional oil and gas production fields.

HORIZONTAL DRILLING

A carefully planned horizontal drilling program can be used for new wells or in existing wells (re-entry) to increase productivity and to reduce the effects of skin damage. The major benefit of horizontal drilling is a significant increase in the amount of formation exposed to the well bore, resulting in increased flow at a lower pressure drop.

Mathematical models can help predict the increased flow because of the well bore extension. These models are typically based on a modified form of Darcy's law for radial, compressible flow in a porous matrix. Screening models are available for use as predictors for reservoirs with varying thickness, porosity, permeability, and pressure.

Table 6 shows the effect of horizontal well bore length on flow rate; the data come from a type R1 reservoir at a 20-psi drawdown. A typical vertical well in a similar reservoir would flow at a rate of 1.5 MMscfd. If a horizontal well were extended 2,500 ft with no significant changes in reservoir properties, the flow rate would theoretically reach nearly 14 MMscfd (a nine-fold increase).

Horizontal drilling costs will typically exceed the costs for drilling a vertical well. Drilling horizontal wells usually requires more time than vertical wells because the curved hole section is drilled along a specific path with a downhole motor.

The first horizontal well drilled in a field may exceed twice the cost of a comparable vertical well. After the fourth or fifth horizontal well is drilled, however, a steep learning curve quickly reduces the cost ratio to about 1.2-1.5.12

Fig. 2 illustrates the decrease in cost for BP Exploration's horizontal wells (including horizontal gas injection wells) drilled on the Alaskan North Slope.1

Another major operator drilled a horizontal well with two branches; the well had double the productivity of a vertical well but cost only 50% more.3

Horizontal wells can help reduce the amount of base or cushion gas required in a storage reservoir because reservoir pressure can be lowered while deliverability remains constant. For a constant 800-psi line pressure at the surface of an R1 reservoir, a vertical well requires a 150-psi pressure drop to maintain a peak deliverability of 11 MMscfd. A 1,000 ft horizontal well can provide the same deliverability with only a 33-psi pressure drop (Fig. 3). Thus, horizontal wells can reduce base gas requirements without reducing peak reservoir deliverability.

Horizontal wells can be expected to reduce base gas 8-12% as a result of the increased flow at lower pressure gradient. In Fig. 3, the base gas reduction (RBG) would be:

RBG = 100 X (950 psi - 833 psi)/950 psi = 12.3%

This calculation assumes an isothermal, ideal gas.

The following are some of the additional advantages of horizontal wells in gas storage reservoirs:

  • The number of sites is reduced, benefitting ecologically sensitive or high-cost surface locations.

  • Because of increased flow rate, fewer wells will be needed to achieve optimal withdrawal/injection rates. With fewer wells, maintenance costs should be less.

  • Fewer surface installations reduce the capital development cost.

  • Directional and high-angle drilling can access the marginally economic parts of the reservoir.

  • A separate injection/production well strategy can be implemented.

  • Water coning is reduced because of decreased flowing well pressure gradients.

  • Well bore stability increases because of the reduced sand-face pressures.

SPECIAL CONSIDERATIONS

Gas storage reservoirs are seasonally cycled from low pressure to high pressure over a life of up to 50 years. This pressure cycling and long life require special considerations in developing a storage reservoir with horizontal wells.

The integrity of the caprock is critical in storage fields. This caprock is usually a stratified layer of impermeable rock overlying the porous zone. Horizontal wells must be designed to prevent leakage of storage gas to surrounding formations. A well-engineered casing and cementing program, critical to the success of horizontal drilling, can mitigate the leakage problem. For example, setting casing at an angle at the reservoir boundary requires excellent cement displacement and bonding characteristics.

Many storage reservoirs are old, depleted oil or gas fields. When an old field is converted to gas storage, pressure in the reservoir may dictate how a well drilling plan evolves. Light-weight, low-solids drilling fluids are required in these wells. Extra effort to increase lubricity will be required if the horizontal well is "slide drilled" (that is, if the drill pipe cannot be rotated or can be rotated only at a slow speed).

Damage to the hole from drilling fluids and drilled solids contamination is a special problem in storage wells. The drilling fluids system, well pressure control practices, and completion procedures must be designed carefully to ensure a low skin factor and a highly conductive well bore.

Other considerations in the application of horizontal drilling technology to gas storage reservoirs include well placement, interference with vertical wells, injection/ production strategies, equipment for high-volume, low-pressure flow, and completion options. As with any complex engineering task, field supervision and operational flexibility are essential to success.

TEST RESULTS

Only 76 horizontal gas wells were completed between 1985 and 1991, according to a recent GRI survey of horizontal gas wells worldwide.4 Activity may increase, however, with more than 50 horizontal gas wells drilled in 1992.

Several horizontal wells have been attempted in gas storage reservoirs recently.4 One operator has completed and is currently testing two of the horizontal wells, but the details of the design and engineering are confidential pending further evaluation. Results of the third horizontal well have not yet been released. The fourth horizontal well was drilled with short-radius technology and penetrated a thin section. The short lateral did not produce more than the vertical well, however.5

The fifth horizontal gas storage well was drilled in the West Edmond storage field in February 1992 under a research project jointly funded by GRI and Oklahoma Natural Gas Co. (OGJ, Feb. 22, pp. 62-63). This re-entry was horizontally extended to approximately 1,500 ft.

With a drawdown of 12% of wellhead pressure, the well had a sixfold increase in productivity compared to that for a vertical well.6 Flow rates in excess of 23 MMscfd were measured during controlled tests.

A report on the ONG field test will be available soon from GRI.

ACKNOWLEDGMENT

The authors wish to thank the Gas Research Institute and Maurer Engineering Inc. for permission to publish this article.

The authors thank the GRI Gas Storage Steering Committee for data and assistance with the study. They also thank Oklahoma Natural Gas Co. for contributions to the field tests.

The authors thank senior engineer Steve Bergin and gas storage manager Anthony Cook with ONG.

REFERENCES

  1. Broman, W.H., et al., "Horizontal-Well Performance at Prudhoe Bay, Journal of Petroleum Technology, October 1992.

  2. DEA-44 International Forum on Horizontal Drilling, Maurer Engineering Inc., Houston, Apr. 28-29, 1992.

  3. Texaco report to shareholders, second quarter 1992.

  4. Gas Reservoir/Wellbore Orientation Screening Study: Survey of Horizontal Gas Wells, final report, Gas Research Institute Report 91-0281, September 1991.

  5. Personal interview with Northern Illinois Gas.

  6. Gas Storage Report, Pasha Publications, Arlington, Va., March 1992.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.