Horizontal well successfully drilled in Black Warrior basin

Johnnie R. Butler
Mississippi Valley Gas Co.
Jackson, Miss.

Butch Skeen
Sperry-Sun Drilling Services
Dallas

The first horizontal well successfully drilled and completed in the very abrasive Black Warrior basin required the use of several state-of-the art drilling technologies and quick decision making at the well site.

Mississippi Valley Gas Co.'s first horizontal well in the Goodwin natural gas storage field has a deliverability about six times that of a conventional vertical well in the same reservoir.

The MVG Howard 35-4 No. 1 was drilled in 23 days during September and October 1995. The well reached 1,805 ft true vertical depth (TVD) and 3,660 ft measured depth. The horizontal section length was 1,650 ft. The well reached the target, and the economics were favorable.

Geology

The Black Warrior basin of Northeast Mississippi and Northwest Alabama is a triangular-shaped structural basin bounded on the east and southeast by the Appalachian front, on the west and southwest by buried Ouachita Mountains, and limited on the north by the Nashville Dome and its gently south-dipping platform (Fig. 1 [46840 bytes]).

Paleozoic rocks in the basin range from Cambrian (570-505 million years old) to Pennsylvanian (286 millions years old), mostly covered with sediments from the Cretaceous period (about 130 million to 65 million years ago) of the Mesozoic era.

Most of the production in the basin is gas from the Mississippian sands at depths of 2,000-8,000 ft. Many of the oil and gas traps are tectonic, resulting from the effects of folding or faulting of the earth's crust. The fluvial-deltaic Mississippian sands, which date back to the early Carboniferous period more than 300 million years ago, provide many stratigraphic traps. There are a few minor oil accumulations with production both from Pennsylvanian and from Ordovician reservoirs.

The Goodwin field is on the northwest flank of the Black Warrior basin. It is a southeast-plunging structural nose of closure in a horst position between two faults. The field was discovered in 1984, and it produced from 1986 to 1992.

Three Mississippian sands carrying gas had been encountered on this structure, with the Evans sand being the primary sand, the Lewis the second, and the Carter having minor gas accumulation. The field's traps were formed by the sands crossing the structure or pinching out upstructure. The sands have low permeability and, being sensitive to formation damage, need special attention during drilling and completing.

Most of the wells drilled during the field's productive phase were fracture stimulated on completion. Together, these vertical (also referred to as conventional) wells produced a total of 2.655 bcf of gas.

Stratigraphic traps within such tight sands may be candidates for natural gas storage if they are also strategically located within the framework of a natural gas utility's distribution system and have previously held gas in place. For a gas storage field to be an economical part of a utility's distribution system, however, it needs to have relatively high rates of sustained deliverability.

A traditional solution has been to drill more wells for storage withdrawal than for production. Technologies such as horizontal drilling are now being investigated as more economical alternatives. In fact, since the advent of horizontal drilling, it has been thought that one of its best applications would be for tight formations, especially those that contain gas, whether for production or for storage.

Goodwin field

Mississippi Valley Gas Co. (MVGC) is a public utility which purchases, transmits, and distributes natural gas to users in its service area. MVGC operates more than 5,000 miles of transmission and distribution pipeline, providing approximately 50 bcf of natural gas service annually to more than 250,000 customers in Mississippi.

As with most natural gas utilities, a large portion of the gas service provided by MVGC is for weather-sensitive heating applications. Thus, gas demand is much higher during the winter heating season than during the remainder of the year. Because of the extreme variability of winter weather in the deep south, gas demand is volatile on a daily basis as well. Both conditions dictate a large role for gas storage.

Contract storage service is available to MVGC from interstate pipeline companies and similar third-party providers. Generally, gas withdrawn from contract storage must be delivered using pipeline firm transportation service, adding significantly to the overall cost. Thus, gas utilities tend to favor development of gas storage fields at points where gas withdrawn can be delivered directly into the utility's transmission and distribution grid, thereby avoiding pipeline firm transportation charges for peak deliveries.

The economics of such "market area storage" improve when the storage location is at a capacity-constrained point on the utility's system. Another benefit of having a storage location at such a point is that it is also a substitute for expensive transmission line reinforcements that would otherwise be required.

During 1993, MVGC evaluated the natural gas storage potential of a number of depleted gas fields in the Black Warrior basin adjacent to MVGC's service territory. One of these, the Goodwin field, was selected for conversion to a storage field because of its size and location.

The low permeability of the target sands was recognized as a negative aspect from the outset. This factor was more than offset by the field's strategic location at a point where capacity was constrained on MVGC's transmission grid and where other reinforcement options were more costly. After the field was purchased, four producing wells were converted to storage injection and withdrawal wells, and four new vertical injection and withdrawal wells were drilled and completed.

Before any more storage wells were drilled, MVGC concluded it should explore the applicability of horizontal drilling, a technology they had not yet used. It seemed logical that deliverability (the rate at which gas flows into MVGC's intrastate transmission and distribution pipeline system) of a single horizontal well would greatly exceed that of a vertical well. The risks would also likely be far greater, however.

Horizontal decision

The Alabama State Oil & Gas Board and the Mississippi State Oil & Gas Board confirmed that only one previous attempt had been made to drill a horizontal well within the Black Warrior basin, but the attempt had been unsuccessful.

The thought of drilling anything but a conventional well in the Black Warrior basin was dismissed by many operators in the area because they thought deviated and horizontal drilling through such hard, shallow formations within such a narrow target range was cost prohibitive.

Nonetheless, the Goodwin natural gas storage field was deemed an area in which it would be beneficial to drill a horizontal gas storage well. The following factors contributed to this recommendation:

The first step in analyzing the potential of a horizontal well was to determine where it should be drilled in the Goodwin field. MVGC had already permitted two new locations, both of which MVGC thought would result in good vertical or horizontal storage wells.

MVGC investigated reentering an existing conventional storage well. The candidate well had never performed up to par and was not situated in a part of the reservoir that had favorable rock properties. The thought was to reenter, sidetrack, and deviate directionally. The well would then be drilled horizontally some distance to very possibly encounter higher quality reservoir rock.

The final analysis, however, was to drill a totally new well. For a project of this magnitude, it was deemed more economical to choose the better of the two already permitted locations. This location would improve the odds of communicating with an area of the reservoir favorable for gas storage, and of potentially greater deliverability. A consulting geologist worked with MVGC to determine the optimum location and orientation path for the horizontal well bore within the permitted and geological constraints.

The next step was to prepare a financial return estimate based on a comparison of the potential performance of a horizontal well with that of a vertical well, given the same formation properties. After analysis using computer modeling, MVGC concluded that in this case the horizontal well's potential performance could indeed justify its additional cost and risk.

Enhanced deliverability was the deciding factor because it was key to the overall success of the storage field development. MVGC authorized the project to proceed, and it assumed the atypical role of operator.

The team scrutinized every aspect of the drilling program beforehand: bit types, kick-off point, build angle, bottom hole assembly (BHA) design, drilling fluids system, target landing depth, weight on bit, drag forces, drillstring design, length of lateral, mud pumps, etc. The team also devised contingency plans that would anticipate problems.

A key factor in the well's success was the team members' positive attitude and thorough work. The team used numerous "what if" scenarios to anticipate problems at every step, but because horizontal well technology had never been implemented successfully in the Black Warrior basin, there could likely be some unanticipated problems.

Spud to TD

There were strong reasons why no one had successfully drilled a horizontal well in the Black Warrior basin. The formations are tight, very hard, and abrasive.

Perhaps the risk of trying to reach a formation for production-where the life of the well would be limited-was indeed not economical to undertake. However, it made sense for a gas utility to attempt accessing a formation horizontally for storage purposes, to risk drilling a well that had the potential to store and deliver gas indefinitely. This perspective was critical in the decision making.

A major factor in the project's technical success was MVGC's willingness to learn from a wide variety of industry experts and written material, discern which information was valuable, and then act upon it. Preparedness and quick decision making ensured not only that the target total depth (TD) was reached but that it was exceeded.

During the first 3 days, 595 ft of surface hole was drilled with a rock bit, the 95/8-in. casing was set, and the well was kicked off at 1,300 ft.

A multishot survey tool was run, and the BHA was then configured with Sperry-Sun Drilling Services Inc.'s gamma ray measurement while drilling (MWD) tool and motor. A journal bearing tungsten carbide insert bit drilled the curve section.

Angle built as intended from 1,300 ft until a little before 1,930 ft, when some problems were encountered maintaining build angle. By correlating the MWD data and formation cuttings with two nearby conventional wells, the bottom hole location was determined at about 26 ft above the storage zone, which was the Evans sandstone.

The bottom hole location was about as close as necessary for two reasons:

• The original plan had called for running the 7 in. long string from surface down to a depth close to the top of the storage zone.
• The storage formation, unlike the well thus far, was overpressured because of gas that had been injected during the preceding months.

The 7-in. casing shoe was drilled out with a 61/8-in. bit run on 31/2-in. drill pipe. The casing was then pressure tested. The mud was a Baroid Drilling Fluids Inc.-designed brine/polymer-based fluid system, which was nondamaging and solids free.

Surveys indicated the well did not have the severe build angle needed to land on target (1,781 ft TVD at 90°). There was concern the target would be overshot, possibly requiring setting a plug in the casing and then milling out a window in the pipe. That night, Schlumberger Well Services was called in to run a wire line survey that could be used very close to the bit. From an open hole truck, a slim hole gamma ray tool on 0.46-in. cable was run down the drill pipe. The data revealed that the well was in a good position because the storage zone was coming in about 10 ft lower than predicted.

To hit the revised target, however, a much more aggressive (short radius) motor was needed. The motor was sent by "hot-shot" to the site from Louisiana. With this short-radius motor, the remainder of the build section was drilled until the top of the storage zone was encountered.

At that point, the well was circulated to check for any gas effect from the energized sand. There was some gas leak off as anticipated. A calcium bromide dissolved salt solution was added to the drilling fluid system to increase the density and balance the system. This expense was necessary to control the well. Drilling another well when the storage field is depleted (at a low pressure) would avoid this cost and may allow somewhat faster drilling.

With the angle now maintained very close to 90°, the effects of the formation played an increasingly larger role. Bit number five was pulled after it drilled 441/2 hr, and it showed severe wear. The motor's stabilizers were also very worn. It was surprising that at such a shallow depth-around 1,800 ft-the formations were so very hard and abrasive.

The abrasive formation also restricted the drilling hours of a polycrsystalline diamond compact (PDC) bit specially designed for horizontal wells. This bit had a short profile to reduce torque. The PDC bit's ability to keep the horizontal section in gauge proved to be beneficial; however, the extremely hard formation limited the bit to 661/2 hr drilling.

The maximum sustained working pump pressure, given the design specifications of the standpipe, kelly hose, and swivel, was no more than 1,800 psi. When drilling started with the PDC bit, pressure was around 1,400 psi. In addition, formation cuttings were very small because of cutting action of the PDC bit and therefore harder to evaluate (than the large cuttings generated from roller cone bits). The value of the MWD gamma ray tool was realized at this time as the team relied increasingly on its output data. Pump pressure steadily increased as the horizontal section was drilled, eventually reaching 1,600 psi with occasional surges. As the pump pressure increased, the quality of the MWD data decreased.

Pressure increased at the surface as well as downhole; in light of these data, MVGC became concerned that the job would remain incomplete.

There was some second-guessing on some decisions about the project. Could the rig, with its limitations, handle the job? Was the right drilling company chosen? Was the drilling fluid system designed correctly? With pump rates low, was fill being left in the hole, creating a potential for stuck pipe?

On the positive side, the well was 1,000 ft into the storage formation, the curve section was smooth, and the pipe was set and cemented. The ultimate goal was a 1,500-ft horizontal section, however. Based on preliminary calculations, that length would meet expectations for deliverability.

The decision was made to pull the bit. When the BHA arrived at surface, the team was relieved because everything was intact, but the PDC bit was severely worn. It was obvious, however, that 661/2 hr drilling was too long for the PDC bit in the very hard, abrasive formation.

The bit had performed well, though, under the circumstances: it had horizontally drilled 557 ft of an extremely difficult formation while remaining in gauge.

To continue with a lower pump pressure, it was decided to proceed with a journal bearing insert bit. The penetration rate increased to about where it had been at the beginning of the previous run. The pump pressure dropped to a manageable 1,400 psi. The quality of cuttings and the MWD data improved significantly. This bit was pulled after limiting drilling with it to 331/2 hr.

With the well less than 100 ft from the targeted 1,500 ft of horizontal section within the storage zone, it was decided to drill ahead using the same type of insert bit. This final bit drilled 249 ft of lateral in 29 hr, reaching 3,660 ft measured depth (Fig. 2 [26695 bytes]).

Analysis

Several technologies were critical for this difficult well to be drilled:

• MWD and gamma ray tools
• Short-radius motor to complete the build section
• PDC bit used in the horizontal section
• Solids-free, calcium bromide polymer fluid system
• Completion procedure using a Halliburton Energy Services jetting tool, run on coiled tubing to the open hole interval, designed to clean the hole with a nitrogen-foamed acid.

This horizontal well was a technical and economical success (Fig. 3 [23965 bytes]). The overall drilling and completion cost of the well was 1.87 times that of an average conventional well in the Goodwin field. The horizontal well's proven deliverability is six times that of a comparable vertical well.

Because only one well was drilled instead of six vertical wells (for the same deliverability increase), MVGC realized a number of other benefits:

• Fewer access roads and gas storage locations are required. Because a storage well is considered permanent, all necessary roads and locations must be built with permanence in mind and then maintained indefinitely.
• Fewer meter runs, gathering lines, and other surface facilities downstream of the wellhead are needed. With fewer wellheads and locations, there is less exposure to liability from third-party damage, and security risk is spread over a smaller area.
• Maintenance, operating responsibilities, and costs are lower.
• There is less environmental exposure.
• The 1,650-ft horizontal section enhances communication with the reservoir.

The Authors