Technology tackles low-permeability sand in South Texas

Terry E. Swift, Paul Mladenka
Swift Energy Co. Houston

Through aggressive applications of advanced technology, Swift Energy Co. increased its natural gas and oil production from the AWP Olmos field in South Texas by more than fivefold in less than 21/2 years.

At the same time, it substantially reduced per unit development and production costs.

Gross daily production was more than 67 MMcf equivalent by mid-1997, compared to about 12 MMcf equivalent in early 1994.

The AWP field in McMullen County, Tex., is a low-permeability, depletion-drive reservoir (the Olmos sand) that releases its vast quantities of hydrocarbons only after being artificially stimulated.

Swift began operations in the field in 1989 after increasing its interest, first obtained in 1988, in several producing properties in the northern portion of the field. Swift immediately initiated a program of infill drilling to increase production, as well as numerous production facility and pipeline enhancements.

After gaining considerable experience in the field, particularly in hydraulic fracture stimulation and in increasing production from declining wells, Swift began expanding its operation in 1994 by acquiring additional undeveloped acreage adjacent to its original leases. Subsequent acquisitions increased its total holdings in the field to 36,000 net acres.

In mid-1995, on the newly acquired acreage, Swift launched an accelerated drilling program that is still under way. To ensure maximum recovery with the lowest possible costs, Swift organized a team from its technical staff to focus on all aspects of field development. The results were improvements in its drilling, completion, and operational programs, including the use of appropriate new technologies, many of which were computer based.

With 16,000 net acres successfully developed through mid-1997, significant savings were realized both in costs and in manpower requirements.

Hydraulic fracturing

Swift's expertise in designing and executing hydraulic fracture stimulations (Fig. 1 [13,395 bytes]) remains the critical component of its AWP field operation.

By the time Swift entered the field in 1989, earlier operators had determined that an economical frac job would have to use a water-based fluid and include ordinary Ottawa sand. In previous attempts, they had used an oil-based fracturing fluid (basically gelled diesel oil) to avoid damaging what they thought might be a water-sensitive formation.

As it turned out, the oil-based fluid, which was costly, not only was unnecessary, but it also caused problems and was not as clean as a water-based gel. Those early operators also tried various high-strength proppants before settling on Ottawa sand.

Soon after beginning its own operation in 1989, Swift further refined the fracturing materials by selecting a more-effective and less-expensive fracturing fluid. It also switched to a resin-coated sand as the proppant material. The coated sand tends to adhere to itself, giving it more strength and helping it stay in the formation rather than flowing back into the well. These changes reduced the job size by more than 50%.

As with the earlier operators, most of Swift's fracture-stimulation problems were related to the Olmos sand not being bounded very well by shale. Rock characteristics of formations above and below the Olmos are similar to those of the Olmos sand, and therefore differences in sand and shale characteristics cannot be used to limit vertical fracture growth. Fractures with vertical heights extending into the shale above or below the Olmos allow fracturing sand to be pumped into unproductive rock.

For Swift's early in-fill drilling program, the lower reservoir pressure caused by partial depletion of the field provided a barrier against the higher pressure retained in the shale. This made it easier to keep the fracs in zone. However, when Swift began drilling in new undeveloped areas in 1995, the reservoir's original higher pressure had to be dealt with. Also, the Olmos sand in the undeveloped areas had lower permeability, necessitating longer frac lengths. As a result, the first fracture jobs in the new areas were increased from 350,000 to 1.4 million lb of sand, depending on zone thickness, permeability, and other physical properties.

Through a detailed area reservoir study in which all the geological and fault data available were collected and analyzed, Swift's staff began designing its fracture jobs for the conditions surrounding each well bore. To keep fracturing costs from being prohibitive, Swift reverted back to using Ottawa sand for its proppant and to pumping only enough resin-coated sand to minimize proppant flowback.

Another important tool employed on the first several wells drilled in the undeveloped area was dead strings for monitoring bottom-hole frac pressure, which is considered to be "the heart beat of a frac job." The dead strings consisted of 11/4-in. coiled tubing run into the well bore and filled with water. As the frac fluid was pumped down the tubing-casing annulus, the tubing pressure was monitored.

With an accurate downhole pressure, the engineer overseeing the frac job could filter out the effects on pressure readings of variations introduced throughout the process, such as friction and fluid densities. Effects not understood could mean that the fractures were going out of zone, communicating with fractures of other wells, starting to screen out, etc. These effects would prompt the engineer to make changes during the job in progress.

After these various effects were thoroughly understood, Swift, to reduce costs, discontinued running dead strings.

As the company continued to seek ways to get the best value for each stimulation dollar spent, it concentrated in four different areas:

1. Reduce overall job size.
2. Use less-viscous frac fluid, which would help control the vertical fracture height growth.
3. Slow the injection rate, also to reduce vertical height growth
4. Implement immediate fracture fluid flowback to induce fracture closure and minimize proppant settling.

With these improvements, Swift reduced its fracture stimulation costs by 30% over the last 18 months while achieving the same production results as with the larger frac jobs.

Remote fracture monitoring

To further increase fracturing efficiency, the company introduced remote monitoring in 1995 (Fig. 2 [8,768 bytes]).

Using a computer network linked by modems, cellular phones, and telephones, operations engineers now monitor each job in real time. Variables such as treating pressures, pump rates, and slurry concentrations are closely monitored on three computer screens at company headquarters over 250 miles away. Job design modifications are routinely made while the job is under way.

The knowledge gained through monitoring successive frac jobs has also enabled continued improvements in frac design. In addition, through remote monitoring considerable savings have been realized in travel and manpower costs.

Velocity strings

In 1989, Swift Energy became the first operator in the AWP field to successfully run velocity strings for artificial lift (Fig. 3 [16,080 bytes]). The company had realized that the gas/liquid ratios of Olmos wells made the wells strong candidates for this economical application.

Previous operators had overcome liquid loading with conventional mechanical lifts that were expensive to install and operate because of well depth, frac sand production, and low productivity index of Olmos wells. By running 11/4-in. coiled tubing, Swift increased production while cutting capital costs in half and eliminating operating and repair costs associated with other artificial lift methods.

Corrosion protection was another benefit of velocity strings. Use of velocity strings to pump anticorrosion chemicals down the annulus and allow flow only up the tubing provides corrosion protection without the well having to be shut in for batch treating.

Slim-hole drilling

Having decided that long-term natural gas production would be best with coiled tubing velocity strings, Swift's operations engineers realized that further savings on materials costs, particularly tubular costs, could be gained by drilling smaller-diameter holes.

Previous operators in the field had used standard 95/8-in. surface casing and 51/2-in. production casing, which was necessary for rod pumps. With velocity strings, the main task was to determine how small a well bore could be without adversely affecting the initial production rate. The evaluation determined that a 75/8-in. surface casing and a 31/2-in. production casing would lead to cost savings from decreased drilling time, lower drilling mud quantities, and less-expensive tubulars (Fig. 4 [24,893 bytes]). Fig. 5 [9,043 bytes] shows a slim-hole bit.

Another advantage of slim-hole drilling was that installation of coiled tubing for artificial lift could be delayed. The smaller well bores prevented flow velocity from decreasing as rapidly as in larger well bores.

Single-stage cementing

Soon after implementing slim-hole drilling, Swift initiated single-stage cementing in lieu of two-stage cementing, which was the predominant cementing process used by previous operators.

Even though single-stage cementing did not reduce the amount of cement, and in fact it slightly increased the volume, it significantly reduced overall job cost by eliminating a stage tool as well as the need for a completion rig.

The main challenge in perfecting the single-stage cementing design was to isolate the freshwater zone at roughly 4,000 ft above the producing interval. To achieve this, the engineers cut cementing pump rates by 50%. This eliminated excessive annular turbulence, which was causing bridging problems.

By adjusting pump rates and other variants such as slurry designs, Swift attained cement jobs with full circulation and zone isolation.

Together, single-stage cementing and slim-hole drilling reduced drilling and completion costs by 10-15%.

Monitoring production

Remote monitoring of natural gas production is one key factor that has kept operating costs down while the number of wells operated has increased. The monitoring system uses solar-powered flow meters (Fig. 6 [13,322 bytes]) that send production data via radio transmissions to a central computer system in the field office. From there, the information is transmitted over a dedicated telephone line to company headquarters in Houston.

Swift now has more than 260 wells connected to the monitoring system, as well as numerous compressors and sales points.

One main benefit of this technology is the reduced manpower needed in the field to maintain wells. Other advantages include improvements in accuracy and accessibility of the production data. The system also allows smoother production by automatically notifying the field crew if a well or compressor shuts down unexpectedly at any time.

The monitoring system will become more important as wells age because it can open and close wells remotely to overcome liquid loading. Although coiled tubing velocity strings significantly delay liquid-loading problems, an eventual decline in production is unavoidable as the formation pressure decreases. The monitoring system's computers can be programmed to open and close the wells on either a time-interval schedule or a pressure-sensitive schedule.

The company's engineers also use the remote production-monitoring system during frac jobs to determine if the fracture is communicating with nearby wells.

Gathering system

As Swift expanded its AWP field operations, the production facility was specifically designed to accommodate new wells. An evolving network (Fig. 7 [40,933 bytes]) of strategically located flow stations in the field is connected to a central facility, where natural gas, oil, and water from all wells are separated at one location. This centralized system greatly reduces gathering expenses by eliminating the need for individual well facilities such as tank batteries.

Natural gas marketing diversification was improved after Valero Energy Corp. constructed 13 miles of 12-in. pipeline from Swift's central facility to its processing plant from which the gas can be delivered to 11 interstate and intrastate pipelines.

Vapor recovery

A vapor-recovery system helps maximize natural gas production by recovering low-pressure, flash-gas vapors from oil tanks and heater-treater separators. The system captures natural gas that is released from oil production when the oil moves from a higher-pressure reservoir into lower-pressure separators and storage tanks.

The recovered natural gas, which has a high energy content and comprises about 1% of total daily sales, is compressed into the sales line.

Besides capturing natural gas that otherwise would be lost into the atmosphere, the vapor-recovery system also significantly reduces volatile organic compound (VOC) emissions at production facilities.

Field performance

With the confidence Swift has gained in applying advanced technologies and instituting other drilling and operating improvements in the AWP Olmos field, the company has greatly expanded its acreage in the field and increased its drilling level from 5 wells in 1994 to 124 wells in 1996. The resulting development has increased Swift's reserves in the field by fivefold, from 38.0 bcf equivalent at the end of 1994 to 200.4 bcf equivalent at the end of 1996. Annual production from the field more than quadrupled during the same period, rising from 2.4 bcf equivalent in 1994 to 11.1 bcf equivalent in 1996. Having drilled 96 Olmos wells, 94 of which were producers, during the first half of 1997, Swift plans another 43 wells for the remainder of the year. Since each producing well has an estimated productive life of 15-20 years, the company is assured of a return on its technology investments.

The Authors