HORIZONTAL FLOW DRILLING REQUIRES FOCUS ON WELL CONTROL

Michael J. Tangedahl
RBOP Oil Tools International Inc.
Houston
Horizontal wells drilled underbalanced or while flowing must have surface equipment and a blowout preventer stack specially designed for circulating operations.
Horizontal wells can be drilled overbalanced, near balanced, or underbalanced. In certain cases, conventional well control techniques do not always apply. During drilling of the lateral section of a horizontal well, the primary means of well control (hydrostatic fluid head) may be ineffective because of abnormal pressures, formation seepage, lost circulation, or flow or underbalanced drilling practices.1
The calculated risks in horizontal drilling can be overcome by using advanced well control techniques. The best safety insurance is the use of the safest well control equipment and methods available.
Some horizontal wells have had drilling fluid losses at rates up to 100 gpm with 800 psi or more well bore pressure at the surface. On some of these wells, the operators saved up to $200,000 per well because they used a rotating blowout preventer (RBOP) and drilled underbalanced.2 4
Horizontal flow drilling and underbalanced drilling are different methods of drilling. The lateral section of a horizontal well can act as a gas separator. Although the vertical column of drilling fluid may provide a calculated overbalanced or near balanced head, migrating gas can push large slugs of oil at significant velocities to the surface. The horizontal driller must evaluate the possible dynamics of a well during planning for well control and blowout contingency.
Functional well control methods for drilling horizontal wells have been developed in specific regions worldwide. Special safety equipment and procedures, however, are still required in most horizontal development applications.
The challenge for horizontal drilling development and underbalanced drilling is to overcome the obstacles of government regulation, reduce pollution dangers, and improve personnel and equipment safety. Well control techniques tailored to the demands of each field can help overcome these challenges.
Several well control elements must be addressed carefully on each horizontal well:
Drilling fluid requirements
Well control procedures and equipment
Surface equipment and special considerations for handling hydrocarbons produced while drilling.
Additionally,personnel training and on site supervision are critical aspects of a successful horizontal well.
UNDERBALANCED DRILLING
Underbalanced drilling has become one of the most economical ways to drill fractured formations (Fig. 1). The method called flow drilling, developed in the South Texas fields, has proven successful worldwide, in areas such as the Midale beds in southern Canada, fractured limestone interbeds in Ecuador and Peru, cretaceous limestone in the southern U.S., and fractured formations in Oman.
In some horizontal wells, vertical fractures are penetrated as the horizontal section of the well is drilled. The drilling fluid exiting the bit is lost into newly drilled fractures, and the annular column of drilling fluid is simultaneously lost into earlier drilled fractures. This reduction in hydrostatic head results in oil and gas influx into the annulus, further decreasing the hydrostatic head. The well can then flow up the annulus naturally (flow drilling).
In a well with a high gas/oil ratio (GOR) and a 10 ppg mud, flow drilling can easily cut the equivalent mud weight to 6 ppg. The net effect can be a significant pressure gain at the wellhead. The resulting intermittent and unpredictable surface pressures require reliable surface equipment to ensure safety and adequate well control.
DRILLING FLUIDS
One of the major considerations in planning a horizontal well is the type of drilling fluid used. The operator must decide whether to use a clear brine/water or a conventional drilling fluid.
Before a final selection on the type of drilling fluids planned, the operator should collect offset well data and talk to other operators in the area.
CLEAR FLUIDS
Clear fluids have the benefit of reduced well bore .damage if lost circulation or seepage occurs. The drawbacks of clear fluids are the expense, hole cleaning capabilities (if viscosifiers are not used), and increased surface pressures during "live well" situations.
Clear fluids will almost always result in higher pressures at the surface and possibly hole cleaning problems if the fluids are not viscosified with polymers. Most polymers, however, also coat the oil droplets in a flowing well and create an emulsion that can be difficult to break at the surface.
Many special oil additives are designed to improve slide drilling rates with clear fluids. Most of these additives, however, contain emulsifiers that can create additional problems. Alternatively, drilling beads and graphite pills can be spotted around the bottom hole assembly to help slide rates increase as the length of the lateral increases.
The commercially available products work differently in each area; thus, the engineer must be aware of emulsion problems before trying these products.
MUD
Standard drilling mud (either oil based or water based) is better in areas where well bore stability is questionable or where well bore damage is not a consideration. Hole stability can be affected by shale stringers with a sloughing tendency. The sloughing shale or shale cuttings need to be carried out of the hole to prevent deposition in dune areas along the bottom of the lateral section.
Drilling muds and viscosified fluids solve hole cleaning problems better than clear fluids. A viscosified fluid lowers surface pressures because of its ability to help prevent gas migration. If gas migration can be reduced, the control of the well at the surface improves because of the ability to keep a maximum amount of hydrostatic head available at all times.
One problem that can occur with drilling muds, however, is that the oil produced during drilling does not tend to break out of the fluids at the surface. Drilling muds can easily be treated to handle up to 30 vol % oil with very few problems.
Several operators have tested mixed metal solutions as an alterative fluid. The cost of these fluids has limited their use in areas where lost circulation or seepage occurs, however.
BOP STACK
The typical blowout preventer (BOP) stack design in low GOR areas has been the two ram stack (blind rams on bottom and pipe rams on top) with an annular preventer then nippled up (Fig. 2). This arrangement has proven adequate for low-GOR fields like the Pearsall field in Texas and the Weyburn field in Saskatchewan. Once drilling begins in the lateral section, a diverter is usually added to handle sudden well control problems at the surface.
In the early days of horizontal drilling, the conventional rotating control head and the two ram stack were quite successful. The three-ram stack allows for an additional set of pipe rams below the blind rams, with the choke and kill fines set between the upper pipe rams and the blind rams (Fig. 3). A rotating blowout preventer (RBOP) should be considered if a high GOR (1,000 scf/bbl) is expected, if flow drilling or underbalanced drilling is desired, or if H2S is present. 25
In Canada, operators are using RBOPs more frequently, especially for drilling high risk wells (H2S or high pressure).4 Many horizontal wells drilled in Canada, the U.S., and northern Mexico have experienced pressures and flow rates at the surface that conventional rotating heads and annular preventers could not safely handle. Limiting hydrocarbon flow is necessary because expanding gas bubbles in the annulus can push large slugs of oil and drilling fluid to the surface at a high velocity. As standard procedure, the BOP stack should be designed for the worst-case well control problem.
When horizontal drilling became commonplace in 1989 90, many operators began to have major problems with well control. The conventional rotating control head was the weak link in well control in the areas where flow drilling, induced gasification, or high GOR was experienced.6 The demands of horizontal drilling exceeded the capabilities of many conventional diverters, and well control problems led to accidents and high costs on some wells.78 An improved diverter was needed.
In conventional drilling, well control problems are handled downhole by drilling fluid weight and lost circulation materials. Flow drilling or underbalanced drilling in horizontal wells became the first challenge to this conventional well control practice.
The dynamic nature of flow drilling often precludes the use of solids or gels to stop the drilling fluid loss downhole. Many horizontal wells have open fractures, and these wells usually either take drilling fluids or flow oil and gas to the surface. Thus, well control is handled at the surface.
ROTATING HEAD
The rotating control head has worked well for years and has performed very well in air and foam drilling. The rotating control head can be safely used for horizontal drilling in low GOR fields and during low pressure operations.
The rotating control head uses one or two stripper rubbers, and these rubbers are designed typically for 0.5 in. of interference between the inside diameter of the rubber and the drill pipe or kelly. The initial seal comes from this interference fit, and consequently, when worn rubbers are in place, low pressure leakage is common. This seal design does not allow for predictable life expectancy, however. The American Petroleum Institute (API) does not recognize the rotating control head as a blowout preventer, and the manufacturers do not rate their equipment with regard to pressure containment.9 11
Therefore, in determining detailed well control parameters, it is important to examine closely the kick tolerance of the diverter for pressure rating and for predictable performance.
The wear on the rotating control head rubber element cannot be monitored or predicted, and once the element begins to wear, its ability to seal is reduced and continues to decrease until complete failure (Fig. 4).
RBOP
The rotating blowout preventer (RBOP) is used with conventional BOPs to maintain surface back pressure up to 1,500 psi while the well is drilled with an under balanced fluid, such as air, gas, or water. 12 14
The RBOP uses hydraulically actuated packing elements supported on large roller bearings isolated by mechanical seals inside a large pressure vessel (Fig. 5). An RBOP has a flange for mounting to the BOP stack and a return discharge flange. Hydraulic oil pressure actuates the packing elements, which ride against the kelly or the drill pipe (Fig. 6). The hydraulic oil pressure can be varied automatically as the well bore pressure varies. With 200 300 psi of hydraulic closing pressure maintained above well bore pressure, the packing element seals around the kelly.
The RBOP bearings are cooled and lubricated by the hydraulic oil used to actuate the packer. This hydraulic oil is contained by two mechanical seals which isolate the rotating packer and bearings from the well bore.
The internal bag type packer element is made in two sections so that a split in the inner section does not result in a loss of actuating pressure. Also, the inner section can be replaced without replacing the outer section. The internal packer opens fully, which eliminates the need to disconnect a portion of the preventer when the bit is removed. The kelly packer element gives a positive seal up to the RBOP working pressure rating on any surface. The kelly packer can be changed by simply releasing the locking mechanism and retrieving the packer through the rotary table.
The RBOP's well bore sealing element, the kelly/drill pipe packer, win wear during drilling. Automatic increases in hydraulic fluid volume are added to the RBOP to compensate for the kelly packer's rubber loss, however. This design ensures the sealing element will not fail catastrophically and will provide the same rated seal throughout the entire wear life of the packer element.
In addition all BOPS, including the RBOP, are designed to the American Society of Mechanical Engineers' pressure vessel codes and the API specifications for annular blowout preventers. Rotating control heads are not.9 15
SURFACE EQUIPMENT
Surface equipment specially designed for circulating should be considered for underbalanced drilling or flow drilling operations. For sour hydrocarbon production during drilling, all equipment should be tested and meet safety requirements for sour service applications.
The diverter is a key element in safe well control practices for horizontal drilling. It and the BOP play an integral part in the surface equipment layout. The two-ram or three ram BOP stack with an annular Preventer and RBOP allows the returns to be taken off the drilling spool between the blind rams and pipe rams or off the flow line or diverter fine on the RBOP. Gas, oil, and drilling fluid returns are taken through the choke manifold (Fig. 7).
Compared to the conventional drilling hookup, the choke manifold requires a few special safety considerations for horizontal drilling:
The true opening through the choke in the open position must be considered carefully. Some manufacturers build chokes with a total opening larger than others for the same nominal choke size. A larger opening can help reduce the amount of back pressure held on the well bore during live drilling when only minimal flow is experienced at the surface.
When heavy fluids are used, flanges should be in place on the choke manifold for installation of a second choke in case the choke nipple should cut away or wash out. In remote areas, a dual choke manifold should be considered.
Because most live well scenarios require all fluids and cuttings to be carried through the choke manifold, a 4 in. manifold with 4 in. side outlets is recommended. The 4 in. manifold is large enough to help dear the solids transported in the drilling fluids. A 4 in. manifold also helps reduce the back pressure on an annulus while the choke is bypassed.
Additionally, all elbows and tees should be "fluid cushioned" and thoroughly inspected. Solids in the return fluids can accelerate a washout in any connection.
After the returns are regulated through the choke manifold, the fluids flow to the gas buster or separator. The separator can consist of a primary and secondary buster, if needed. The vessel should be designed for gas separation with sufficient size and distribution to minimize the effects of burning oil while flaring gas.
In addition, large diameter flare lines (6 12 in.) should be used, and a flare pit of extraordinary size should be built. An electric igniter should be installed at the flare pit. In gaseous regions, it is common to have a continuous flare 50 100 ft high with an annular pressure in excess of 1,000 psi.
The returns flow from the mud/gas separator to the containment tanks for final separation. The oil is pumped to storage tanks, and then transported off location for treatment and sale. The drilling fluid is cleaned and returned to the rig for reuse while drilling continues.
ACKNOWLEDGMENT
The author would like to thank Rick Stone, Larry Cress, and Jeff Cummins and all the companies that assisted in the preparation of this article.
REFERENCES
Von Flatern, R., "Technology Keeps Pace With Horizontal Drillers, The Pitfalls of Horizontal Drilling," Petroleum Engineer International, November 1992.
Cress, L., Stone, R., and Tangedahl, M., "History and Development of a Rotating Blowout Preventer," IADC/SPE paper No. 23931, presented at the International Association of Drilling Contractors/Society of Petroleum Engineers Annual Drilling Conference, February 1992.
Stone, R., and Tangedahl, M., "Rotating Preventers: Technology for Better Well Control, World Oil, October 1992.
Eresman, D., "Underbalanced drilling guidelines improve safety, efficiency," OGJ, Feb. 28, 1994, pp. 39 44.
Deis, P., Churcher, P., Turner, T., and Curtis, F., "Infill Drilling in the Mississippi Midale Beds of the Weyburn Field Using Underbalanced Horizontal Drilling Techniques, paper No. 93 1105. presented at the Canadian Association of Drilling Engineers/Canadian Association of Oilwell Drilling Contractors meeting, 1993.
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Britton, J., "Testing The Rotating Blowout Preventer, An Independent Evaluation," Stress Engineering Services Inc., January 1991.
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Copyright 1994 Oil & Gas Journal. All Rights Reserved.