INNOVATIVE TECHNIQUES CUT COSTS IN WETLANDS DRILLING

Armando R. Navarro
ARCO Oil & Gas Co.
Lafayette, La.

A creative approach to drilling oil and gas wells in sensitive wetlands areas contributed to a savings of over $1.2 million on a three-well, $3 million drilling project in South Louisiana.

ARCO Oil & Gas Co. drilled a three-well project in the Bayou Sale field with a truck-mounted workover rig and a modified solids-control system. This smaller equipment eliminated the need to build a large location in the marsh.

Traditional drilling techniques require a large drillsite to accommodate all the equipment of a modern drilling complex. However, recently imposed environmental regulations substantially limit, and in some cases prohibit, the use of these conventional techniques for drilling wells in wetlands areas.

Based on the potentially huge economic and operational impact on the drilling industry because of these stricter regulations, alternatives to these traditional practices are essential.

WETLANDS REGULATIONS

Louisiana, along with the nation as a whole, is facing increasing environmental scrutiny with particular attention directed toward the marshes and wetlands. As a result, many states have implemented stricter regulations which govern the permits for drillsite construction in these areas.

With the recent concept of "zero net wetlands loss," obtaining permits to construct drilling and production locations has become a regulatory nightmare. Previous regulations were designed only to minimize detrimental environmental impact to wetlands areas, but the implementation of these new regulations limits the use of wetlands areas for drilling oil and gas wells.

Under the jurisdiction of these regulations, obtaining permits to construct drillsites can now take up to 12 months, thus jeopardizing the ability to meet lease and economic deadlines.

Also, these strict regulations do not allow the discharge of drill cuttings. Thus, it can cost the oil industry thousands of dollars per well to haul drill cuttings to approved disposal sites.

STANDARD DRILLSITE

Standard drilling industry practice requires a drillsite sufficient in size not only to erect a drilling unit, but also to construct reserve (earthen) pits and place other pertinent drilling equipment onto the location.

The main structural components of a rig are the substructure and the derrick, which make up the hoisting system. The primary function of the hoisting system is to support the rotary table and provide the appropriate equipment and working areas needed for lifting, lowering, and suspending tremendous loads during drilling operations, The forces exerted by these loads on the weak marsh usually require that cluster pilings be driven beneath the substructure for support.

The peripheral equipment, which includes the circulating and power equipment, occupies a major physical portion of the drilling location. The circulating system provides the equipment and working area to prepare and maintain the drilling fluid. The power equipment generates the primary power to operate the entire drilling operation. Any limitation in the size of the power equipment because of drillsite restrictions can severely hamper power deliverability and thus the efficiency of the drilling operation.

The largest space-consuming component of the drilling operation is the reserve pit system, which can include several individual earthen pits. The various pits contain emergency drilling fluid, store water for drilling fluid makeup, and retain drilled cuttings and fluid for treatment before a final disposition by landfarming, annular injection, or hauling off to an approved disposal site.

LOCATION

In Bayou Sale, ARCO considered two key factors in the planning of its three-well program:

Having the wells on-line to meet the winter market
Minimizing wetlands use for the surface locations of the wells.

With the implementation of the stricter environmental regulations potentially delaying the approval of location permits by as much as 12 months, there was the possibility of losing several million dollars in revenue by missing the winter market. Also, with the prospective drillsites located in wetlands areas, each new location could cost as much $500,000 to build.

Several options were explored to avoid the regulatory roadblocks and the exorbitant costs of building new locations in the marsh. The most viable option included the drilling of directional wells from existing drilling and production pads.

The main problem with the use of existing drilling and production pads, without expanding the pad and affecting the surrounding marsh, is the location of the existing well on the site. Typically, pads are built such that the well is drilled near the center of the site.

The location of the well in the center allows room for a conventional rig and the peripheral equipment with minimum wasted space (Fig. 1). The downfall to this placement technique is that only one well, if productive, can be drilled on each pad with a conventional rig and without expansion of the location.

There were two such pads located in Bayou Sale field with the potential to be used as drillsites for this project. After investigating several conventional rig layouts for drilling the three wells, it was determined that fitting a conventional rig onto the locations without expanding the pads was not achievable.

RIG SELECTION

The use of a minimum-area, truck-mounted workover rig to drill the wells was then considered. In concept, this is an ideal resolution to the limited space problem because of the small area needed for the drive-in rig (Fig. 2). Unfortunately, past experience has shown that efficiencies of a truck-mounted rig are as much as 50% less than that of a full-size drilling rig, thus negating any anticipated advantage.

Some of the factors investigated to qualify a minimum-area, truck-mounted workover rig for the project were the derrick and substructure load capabilities, rig power deliverability, rotary table torque capability, and fluid pump capability. In particular, a thorough investigation was made as to the capabilities of a 900-hp, truck-mounted workover rig. The rig was equipped with a Wilson 116-ft, 369,000-lb nominal capacity derrick and two Gardner Denver PZ-9 fluid pumps powered by two Caterpillar 475-hp diesel engines.

The study indicated that by carefully planning the wells (i.e., well path, casing program, and drilling fluid density) while keeping in mind the limitations of the rig, the three 11,000-ft directional wells could be efficiently drilled and cased with the truck-mounted rig. The program objectives would not be jeopardized.

The drive-in rig requires only one third the area that a full-size conventional rig requires. Thus, it was possible to drill two additional wells from the first existing drilling and production site and one additional well from the second site. Fig. 2 shows the equipment layout for the two additional wells adjacent to the existing well on the pad. The use of these setups without having to extend the pads or build new locations saved approximately $1 million on the three-well project.

SOLIDS CONTROL

The stricter environmental regulations prohibit the construction of earthen pits and the discharge of drill cuttings and fluids. Thus, the use of a closed-loop system for solids control was required. The main objectives of a closed-loop, solids-control system are the efficient separation of drill solids from the drilling fluid and the minimization of the amount of low-gravity (colloidal) solids retained in the system.

Previous methods of closed-loop solids control used by ARCO included either a completely mechanical system or a chemically enhanced mechanical system. The completely mechanical closed-loop, solids-control system comprises multiple shakers and centrifuges (Fig. 3). The chemically enhanced system essentially is composed of the same shakers and centrifuges but also contains a chemical injection unit for further solids separation.

Evaluation of these systems on previous wells drilled in the Bayou Sale field indicated that the systems were very effective in the separation of drill solids and the minimization of low-gravity solids buildup. However, the cost to operate and maintain these systems is quite expensive because of the amount of equipment necessary for efficient operation.

Limited space and the relatively low budget wells made a viable alternative to these elaborate closed-loop, solids control systems desirable. Planning called for each well to be drilled in less than 20 days and with fluid densities not to exceed 10 ppg.

ONE-STEP SYSTEM

"One-step" solids control best met the project's needs. This system essentially uses only two pieces of equipment: one shaker and one 12-in. dual hydrocyclone mud cleaner (Fig. 4). The shaker is a typical high-speed shale shaker. The 12-in. dual hydrocyclone mud cleaner uses centrifugal force to separate solids from the mud without the need for dilution.

The 12-in. dual hydrocyclone processes the total fluid system (up to 1,200 gpm). Thus, particularly in low-density fluid systems, it reduces the need for several other pieces of solids-control equipment such as desanders, desilters, mud cleaners, and centrifuges.

The elimination of the other solids-control equipment realized a cost savings of $80,000 on the project, and the physical space requirement of the system was substantially reduced.

The efficiency of closed-loop, solids-control systems can be measured by the amount of cuttings and fluids hauled off compared to the amount of hole drilled (expansion factor) and by the percentage of low-gravity solids remaining in the mud system after the mud is processed through the solids-control equipment.

The evaluation of the system's performance upon completion of the three wells indicated that the drilling fluid properties were actually superior to that of similar wells drilled with the more elaborate closed-loop systems. Also, the hauled off waste volumes were less than that of the other wells.

On three previous wells (denoted as Well Pl, Well P2, and Well P3) drilled with the more elaborate closedloop, solids-control systems, the expansion factors ranged from 2.75 to 3.60.

In contrast, the expansion factors ranged from 1.10 to 1.50 on the wells drilled with the dual hydrocyclone system (Fig. 5). Normalizing for hole size variances, the drop in expansion factors reduced the haul off volume by 12,000 bbl on the three-well program. At a cost of $10/bbl for hauling off fluid and cuttings to a disposal site, ARCO saved about $120,000 on the project.

A high percentage of low-gravity solids (5%) in the fluid system contributes to increased dilution volumes. The one-step, solids-control system maintained the lowgravity solids at 4% or less for each well. In contrast, the low-gravity solids percentages in the more elaborate systems, taking into consideration the fluid density variances, were between 5% and 8%. This reduction in lowgravity solids led to less water dilution and thus less waste to haul off.

Another benefit of the smaller closed-loop system is the reduced drilling fluid chemicals cost. Because the low-gravity solids buildup is minimized, the dilution volume is reduced, thus reducing the amount of drilling fluid chemicals required by the system. A comparison of the three wells on this project to a similar well which used an all mechanical closed-loop system shows the benefit of reduced dilution volumes. The mud chemical costs ranged from $0.50/ft to $0.95/ft on the three wells compared to $1.60/ft on a similar well (Fig. 6). (Only one other well had a similar mud weight and was used for a comparison to the three-well project.) This reduction in chemical additions saved approximately $50,000 in drilling fluid costs on the three-well project.