Sheila Baron, Stephen Skarstol
Energy Resources Conservation Board
Calgary
A set of equations, based on kick tolerance theory and the driller's method of well control, helps determine the optimum depth for setting surface casing.
Operators can drill wells more safely by understanding the primary purpose for surface casing instead of automatically setting the casing to a depth prescribed by regulations.
This new method is the basis for recent regulation changes on surface casing setting depths in Alberta. The depths determined with the new method compare favorably with the depths currently used by industry.
The optimum setting depth for surface casing can only be determined with an understanding of why surface casing is set. The drilling industry has not yet answered the following question satisfactorily: Is the primary function of surface casing to protect aquifers, to provide hole stability, to allow a kick to be circulated out, to or allow the well to be completely shut-in after a kick has been detected?
Although the surface casing has many purposes, its primary function is to allow a kick to be circulated safely out of a well. The North American oil industry regulators believe that the full-length cementing of the casing string next to the surface casing provides adequate long-term protection of freshwater.
The new requirements in Alberta should ensure that fracturing to surface is prevented by the ability of the formation at the surface casing shoe to tolerate kick pressures during the driller's method of well control. For shallow wells (
Leak-off testing each well is necessary to ensure that the leak-off gradient is at least 22 kPa/m (about 1 psi/ft). if the gradient is less, an alternative to the driller's method of well control, such as the low-choke method, should be used to circulate out a kick.
Implementation of the new base requirements in Alberta may slightly increase costs to the industry. In some areas, however, the new surface casing reduction system may cut surface casing costs without compromising the ability to control a well.
REGULATIONS
In the U.S., surface casing depth requirements differ from state to state. The majority of the oil-producing states require surface casing to be set below all freshwater.
A few states (Idaho, for example) require surface casing to be set "sufficiently deep to prevent blowouts" and require all freshwater to be covered.1 Several states (California, for example) base surface casing requirements on the depth necessary for well control by a relationship to total depth.2 California has very deep freshwater (as deep as 900 in) which cannot be feasibly covered by surface casing. To protect freshwater, California requires that intermediate or production casing "be cemented so that all freshwater zones, oil or gas zones, and anomalous pressure intervals are covered."2
Indiana's surface casing rule simply states that surface casing be set "below all freshwater, except where production casing is cemented to surface."1
Some of the state regulatory bodies (Oklahoma Oil and Gas Conservation Board, for example) that require surface casing apparently only for the purpose of covering freshwater may impose a greater depth for well control purposes if the depth to cover freshwater is too shallow. In Oklahoma, all wells drilled to less than 760 m are not required to have surface casing set through freshwater; rather, the next string must be cemented to cover the freshwater.1
The Texas Railroad Commission (RRC) allows alternative freshwater protection programs through an exception process. The RRC may allow companies to set less surface casing providing the first string of casing set through the deepest freshwater is "cemented from the shoe to ground surface in a single stage if feasible."3 Also in Texas, any well drilled to less than 300 m is not required to have surface casing set through freshwater, "provided that production casing is cemented from the shoe to ground surface."3
CANADA
The western Canadian provinces have total depth relationships for surface casing requirements similar to California's requirements.
British Columbia requires surface casing to be set at 15% of planned total depth.4 Saskatchewan requires surface casing to be set at 10% of planned total depth.5 Alberta's requirements prior to 1993 were 5-10% of planned total depth for developed areas and 12-20% of planned total depth for exploratory areas.6 To protect freshwater, the Energy Resources Conservation Board (ERCB) of Alberta requires that wherever surface casing is set "less than 25 m below any aquifer which is a source of useable water, the casing string next to the surface casing shall be cemented full-length."7 (By definition, useable water contains less than 4,000 mg/l. total dissolved solids.)
In Alberta, the requirement for surface casing is often waived for shallow wells providing "the casing shall be cemented full-length."7 In Alberta, every license to drill a well has the following provision All useable groundwater aquifers in a well shall be isolated behind surface casing or adequately covered by the cementing of the next casing string or, if the well is to be abandoned, with appropriate open hole abandonment plugs. For drilled and abandoned wells, Alberta's requirements allow companies to use their abandonment program as a means to cover freshwater.
It is clear that oil and gas industry regulators believe the full-length cementing of the string next to the surface casing provides adequate protection of freshwater.
SURFACE CASING DEPTH
Surface casing has several important functions:
- The pressure integrity at the surface casing shoe determines the ability to shut-in the well during a kick.8
- Surface casing protects freshwater sands from contamination.9
- Surface casing isolates the shallow unconsolidated sections to combat drilling difficulties.8
- Surface casing helps contain surface pressures resulting from a kick.9
The hydrostatic head of the drilling fluid is the primary means of preventing a kick during drilling operations. An influx of fluids can occur when formations are normally pressured, however, by swabbing in a kick during a trip out of the hole. Most blowout prevention equipment allows safe circulation of a kick or shut-in during well control.
Surface casing is an integral part of the well control system, just as blowout preventers and the bleed-off system are. If surface casing is set too shallow, such that a kick cannot be circulated out of the well without exceeding fracture pressure, a blowout may result.10 Successful kick control requires the well be cased sufficiently to contain the maximum possible surface pressures.9
- Does the surface casing need to be set deep enough to withstand pressures resulting from the complete shut-in of the well after detection of a kick?
Alliquander investigated various methods, all based on well control, of determining surface casing setting depth.11 The method that assumed the well was completely shut-in, and therefore accounted for pressure inversion, showed that for every 10 min the well was shut-in, the required surface casing depth doubled. The conclusion was that after a kick is taken, "the hole should be closed for a very short time only," and the driller's method of well control should be used to kill the well.11
- is surface casing the only means of long-term protection of freshwater aquifers?
Many oil industry regulators believe a cemented string next to the surface casing or the use of an abandonment plug provides alternative methods of long-term protection for freshwater aquifers.
By casing-off shallow, unconsolidated formations, drilling problems such as sloughing and stuck pipe can be avoided. Many regulators require casing to be set across an impervious zone or below the lowest occurrence of sand or gravel.17 Casing these zones provides hole stability and ensures that the rock at the surface casing shoe is able to withstand pressures during the circulation of a kick. Thus, the surface casing ensures that only reasonably competent formations are open below for safe well control.
- What is the primary function of surface casing?
If the complete shut-in of a well would require unreasonably deep (and therefore uneconomic) surface casing, and if aquifers can be protected for the long-term by alternative methods generally accepted by regulators, and if by providing hole stability surface casing also ensures only reasonably competent zones are open below it for the purpose of well control, then, by elimination, the primary function of surface casing is to allow the successful circulation of a kick.
Therefore, surface casing must be set deep enough so the circulation pressures after a kick are less than the formation breakdown pressure.
KICK TOLERANCE
The following general surface casing depth guidelines were determined from a review of literature (Aadnoy, et al.; Koski and Adams; and Winchester) covering casing point selection based on blowout prevention requirements:
- 230 in surface casing for a 1,200-m intermediate hole (about 20% of total depth)12
- 400 in surface casing for a 2,000-m well (20% of total depth)13
- 1,220 in surface casing for a 3,050-m well (40% of total depth).14
These depths were based on a variety of assumptions, including initial pit gains from 5 to 16 cu m.12-14
These depths are much greater than those from industry regulators, who base their requirements on well control and allow surface casing depths of 5-20% of total depth. Well economics, especially if a well is drilled and abandoned, could be significantly affected by the methods proposed by Aadnoy, et al.; Koski and Adams; and Winchester.12-14
The following proposed method of determining surface casing setting depth yields depths in the range currently used by operators in North America. Assuming the driller's method (constant bottom hole pressure) of well control is used, Equation I can be used to derive a solution for the optimum surface casing depth.15
The following assumptions simplify Equation 1:
- The gas gradient is negligible (Hgas = 0).
- The gas behaves ideally (PfVf = PV).
- To tolerate a kick, the kick pressure at surface casing depth must be limited to the leak-off pressure at the shoe.
By using these assumptions and substituting with Equations 2-6, Equation 1 can be rearranged as a quadratic equation (Equation 7). Solving the quadratic equation yields the minimum surface casing setting depth, x (Equation 8).
In the derivation of this equation, it is assumed that the kick pressure must be tolerated at the surface casing shoe. The assumption equates the kick pressure to the leak-off pressure at the casing shoe. This key assumption restricts the optimum surface casing setting depth by tolerating a kick only at the casing shoe.
Thus, if weaker formations are below the shoe, an underground blowout may occur. The most important safety aspect is to control the well at surface. Therefore, the competency of the surface casing shoe is the single most important parameter in preventing a fracture to surface.
LEAK-OFF TESTS
Other methods of picking the optimum casing point have concentrated mainly on determining the formation fracture or leak-off gradient. Formation leak-off gradients cannot be predicted with any reasonable certainty, however.
The variables in formation fracture theory include lithology, fracture mechanism, mud properties, formation pore pressure, geologic stress, formation age, and depth. 12 16 Leak-off testing at each casing seat is necessary because of the inability of any theoretical procedure to account for all possible formation characteristics.17
Although leak-off testing procedures are crude and can lead to variations in data, they will generally yield a reasonable minimum leak-off gradient for a given well.12 Leak-off gradients from a given well cannot be applied to adjacent wells because of the wide range in results. Fig. 1 shows the severe scatter of leak-off gradient data from a sample area in Alberta.
If a competent zone were defined by a minimum formation leak-off gradient, there would be no need to use theoretical methods to determine fracture gradient. Instead, individual well leak-off testing would be necessary to ensure that the minimum is met.
If a leak-off test determines that the gradient is less than the minimum, then the driller's method of well control may result in casing pressure exceeding the maximum allowable casing pressure (MACP). An acceptable alternative method, such as the low-choke method should then be used.
Approximately 75% of the data points in Fig. 1 are above 22 kPa/m. The 22 kPa/m value approximates the average overburden gradient in most areas. Thus, a competent zone is defined as having a leak-off gradient of at least 22 kPa/m. If more emphasis were placed on choosing a competent zone for the casing seat, the number could approach 100%. It is recommended that 22 kPa/m be used as the formation leak-off gradient in the kick tolerance equation.
Fig. 2 shows the results from using the kick tolerance equation, assuming a 3 cu in pit gain or initial kick volume. The kick tolerance equation yields surface casing depths in the range of 10-30% of total depth. These values compare favorably to the depths currently used by industry as dictated by regulators.
ALBERTA REQUIREMENTS
The Alberta ERCB has recently revamped its surface casing requirements. Two drafts of the ERCB's guide, "Surface Casing Depth - Minimum Requirements," were circulated through the oil industry, and the new requirements were largely accepted. The new guide has eliminated the most confusing aspects of the previous requirements in Alberta and has allowed the industry to more easily determine the amount of surface casing required. The new requirements should also ensure that fracturing to surface is prevented by the ability of the formation at the surface casing shoe to tolerate kick pressures.
The new system uses the ERCB's previous curve which was based on a formation fracture gradient of 22 kPa/m at the surface casing shoe and a reservoir pressure gradient of 10 kPa/m. The built-in assumption in the curve was that 27.5% of the reservoir pressure must be held at the surface casing shoe for wells drilled to 3,600 in. This percentage increases linearly to 50% of reservoir pressure for a theoretical zero well depth.
The changes included a system that modifies the curve by allowing the use of reservoir pressure gradients greater or less than 10 kPa/m (Fig. 3). In the decision to retain this part of its requirements, the ERCB compared its curve to results from the kick tolerance method (assuming an initial kick volume of 3 cu in).
The ERCB's curve yields less surface casing than the kick tolerance method for wells less than 800 m in depth and more surface casing for wells in the 1,500-3,600-m depth range (Fig. 2). Overall, the comparison is fairly close, and the justification for retaining the curve is that the low-choke method of well control has been successfully used in Alberta's shallow wells.
The use of the low-choke method allows less surface casing than the driller's method because casing pressure is deliberately held just below the MACP. In the driller's method, casing pressure is allowed to rise to the MACP and then fall.
The low-choke method can require numerous circulations before the influx can be completely circulated out of the well bore. By comparison, the driller's method theoretically requires only one circulation to remove a kick from the well bore. Thus, the low-choke method is not desirable in deeper wells because of the large volume of fluid to be circulated. Many circulations may be needed, increasing the risk of failure in the bleed-off system.
The margin of safety gained by requiring deeper wells to have more surface casing than calculated by the kick tolerance equation is justified because actual leak-off tests may yield a formation fracture gradient less than 22 kPa/m.
REDUCTION SYSTEM
The second draft of the ERCB's guide included a reduction system that allowed for less surface casing than determined by the system shown in Fig. 3. The reduction system is based on well control.
The oil industry thought the 3-cu in initial kick volume, used in the kick tolerance method, was too high. The argument was that kick volumes could be limited to 1.5-2.5 cu in where electronic pit volume totalizer (PVT) systems were in use.
Winchester states that 5-8 cu in (30-50 bbl) is a reasonable estimate for conditions frequently encountered.14 According to Aadnoy, et al., 5 cu m is a typical detectable kick volume.12
The ERCB agrees with industry that recent advances in technology should allow earlier detection of kicks. Thus, for casing design, the detectable kick size can be limited to less than 3 cu in.
Based on the kick tolerance method, the surface casing depth is proportional to the square root of initial kick volume. The ERCB reduction system uses the square root of kick volume in determining reduction factors as follows:
The first tier reduction factor of 0.91 can be applied to the surface casing depth determined for any well proving the PVT is installed, or a leak-off test is conducted.
The second tier reduction factor of 0.71 can only be applied to low-risk development wells. A low-risk well is defined as a well drilled in a field where the kick rate is less than 3 kicks per 100 development wells drilled. The reasoning is that the substantial 30% reduction in surface casing setting depth should be applied only where there is a high degree of confidence, that is, where reservoir pressure and other data are well known and where the risk of taking a kick is small.
The third tier reduction included in the ERCB's guide is for locations where surface casing may be reduced to the historical setting depth. This reduction can result in surface casing set as shallow as 5% of planned total depth, which is insufficient to circulate a kick using the driller's method.
Because the low-choke method must be used where there is a high risk of a failure in the bleed-off system for deep wells, the ERCB requires an emergency flare line to be installed. In addition, because the low-choke method relies heavily on the MACP value, a leak-off test is mandatory. Finally, this type of reduction can only be applied to low-risk development wells that use a PVT system that sends an alarm for a 1.0 cu m kick.
Accurate determination of the leak-off pressure is essential during well control.18 Although leak-off tests are only mandatory for wells with reductions to historical setting depth, the ERCB strongly encourages leak-off testing on all other wells to ensure accurate determination of leak-off pressures.
FINANCIAL IMPACT
The regulations in Alberta stipulate that all useable aquifers must be covered by either a cement sheath or surface casing. In many cases the surface casing setting depth is not deep enough to cover all useable aquifers, and therefore the next casing string must be cemented full-length or staged to ensure aquifer coverage.
The new regulations in Alberta have resulted in deeper surface casing for some areas, increasing the potential for aquifer coverage by the surface casing. In pools where the deeper surface casing covers the aquifer, the cement top requirement for the next string has often been lower.
Prior to any changes in the surface casing requirements, a study tried to determine if there would be some offsetting cost savings in cementing. Six pools with depths from 700 to 3,600 m in central and southern Alberta were selected at random (Table 1). Pools in northern Alberta were not selected because of a limited amount of aquifer data.
Fig. 4 shows the additional surface casing costs ($70/m, which includes surface casing and additional surface hole costs) that would be incurred under the new system for the six pools. The approximate offsetting cementing costs include $1,500 for fixed costs, $10.50/m for cement, and $2.00/m for cement service. (These costs are book prices and therefore a 40% discount was applied.)
In three of the pools, the deeper surface casing covered the useable aquifers, thereby reducing the long string cementing costs. Fig. 5 shows the overall cost changes because of the new system.
In five of the pools, the overall effect is an additional capital outlay averaging $4,000 and ranging from $2,000 to $9,000. The Okotoks-Wabamun B pool, however, had a net decrease in costs as a result of surface casing aquifer coverage. In this example, the additional surface casing costs were completely offset by lower cementing costs.
The three-tier reduction system may also help offset the increased costs. For tier one, a 10% reduction in surface casing costs can be realized for any well where a PVT system with a 2 cu m alarm is used or where a leak-off test is conducted. For many years, the deeper wells drilled in Alberta have used rigs equipped with PVT systems. Thus, the 10% savings in surface casing can be realized without incurring additional cost.
For shallower wells, the cost of renting a PVT system can be offset by the surface casing reduction (PVT rental for 10 days is approximately $1,500, and the cost is approximately offset by a 20-m reduction in surface casing setting depth, at $70/m).
The tier two reduction for low risk development wells can decrease surface casing costs by 30%. Wells eligible for the tier-three reduction may have the setting depth requirement revert back to the historical depth, resulting in no increase in surface casing costs (the Harmattan East-Rundle pool, for example).
In general, the changes were expected to result in slightly increased costs to industry. In areas where full-length cementing of the next casing string was already required or in areas such as the foothills where deep useable aquifers exist, the potential for offsetting cementing costs is low. In other areas, such as south-central Alberta, however, there is potential for lower cementing costs to partially offset increased surface casing costs. Furthermore, the three-tier reduction system may also offer some cost relief in areas where it is applicable.
ACKNOWLEDGMENT
The authors wish to thank Dale Eresman, drilling supervisor with the ERCB, for his assistance and his ideas for this article.
REFERENCES
- Interstate Oil and Gas Compact Commission, "Summary of State Statutes and Regulations for Oil and Gas Production," 1992.
- State of California Department of Conservation, "California Code of Regulations," Title 14, Register 88, No. 22-5-28-88.
- Railroad Commission of Texas, "Statewide Rules for Oil, Gas, and Geothermal Operations," Oil and Gas Division, 1992.
- British Columbia Petroleum Resources Branch, "Drilling and Production Regulations," 1991.
- Saskatchewan Energy and Mines, "Oil and Gas Conservation Regulations," 1992.
- Energy Resources Conservation Board of Alberta, "Minimum Surface Casing Requirements and Exemptions-ERCB Guide G-8," 1986.
- Energy Resources Conservation Board of Alberta, "Oil and Gas Conservation Regulations," AR19/90.
- Petroleum Industry Training Service of Alberta, Drilling Practices Manual, 1989.
- Moore, W.W., Fundamentals of Rotary Drilling, Energy Publications, 1981.
- Goins, W.C. Jr., and Sheffield, R. Blowout Prevention, Gulf Publishing Co., 1983.
- Alliquander, O., "Design Methods of Setting Protecting Casing String in Hungary," American Institute of Mining, Metallurgical and Petroleum Engineers, 1974.
- Aadnoy, B.S., Soteland, T., Rogalund, U., and Ellingsen, B., "Casing Point Selection at Shallow Depth," presented at the 1989 Society of Petroleum Engineers/International Association of Drilling Contractors Annual Drilling Conference.
- Koski, G., and Adams, N., "Casing Setting Depth Selection Important in Blowout Prevention," Drilling Canada, Vol. 2, No. 1, January 1981, pp. 41-42.
- Winchester, P.H., "Surface Casing Design Considerations with Emphasis on the Bass Basin," APEA, 1987.
- Mills, P.G., Blowout Prevention Theory and Applications, IHRDC, 1984.
- Rehm, B., Pressure Control in Drilling, Petroleum Publishing Co., 1970.
- Adams, N., Well Control Problems and Solutions, Petroleum Publishing Co., 1980.
- "Formation Fracture Pressure Facts Needed in Effective Arctic Well Control" Oilweek, Vol. 23, No. 44.
- Baron, S., Skarstol, S., "Surface Casing and Well Control," presented at the Canadian Association of Drilling Engineers/Canadian Association of Oilwell Drilling Contractors spring conference, Calgary, Apr. 14-16, 1993.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
