Prologue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

History of Swift’s AWP Olmos Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Swift’s Early Operations (1989-1994) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Expansion into a New Area (1995) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Further Expansion and Infrastructure Upgrades (1996) . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Sustained Drilling Program (1997) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

A Shift of Emphasis (1998) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Focus on Fracture Extensions, Velocity Strings (1999). . . . . . . . . . . . . . . . . . . . . . . . . . 12

The Year 2000 and Beyond . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Technology Sidebars

Hydraulic Fracturing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Velocity Strings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Slim-Hole Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Remote Monitoring of Fracturing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Single-Stage Cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Gathering System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Remote Monitoring of Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Transportation and Processing Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Pipeline Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Increased Recovery from Fracture Extension Program . . . . . . . . . . . . . . . . . . . . . . . . . 11

Environmental Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Table of Contents

In recent decades natural gas has become recognized as one of the major fuels driving the U.S. economic engine. In addition to providing direct heating for a high percentage of homes and other structures, natural gas is increasingly the energy source that utilities are using to gener-ate the nation’s electricity. As a result, the U.S. Energy Information Administration estimates that the demand for natural gas will rise by 47% between 1997 and 2020—more than that for any other energy source, including coal and oil.

Prologue

4

3

2

1

01985 1990 1995 2000 2005 2010

As conventional sources of natural gas are depleted, meeting this rising demand will depend more and more on the production of natural gas that is bound in tight formations. According to estimates by the Gas Research Institute, tight formations will provide 14% of the nation’s natural gas in the year 2000 and will continue contributing higher amounts in future years.

However, achieving production from tight formations is much more difficult than from conventional sources. With the hydrocarbons so tightly bound within their matrix, their flow through the reservoir and into a well bore is minimal unless the reservoir surrounding the well bore is artificially stimulated—a process that is both technically difficult and economically challenging. In addition, tailored drilling and reser-voir-to-surface lifting techniques are often required.

Such is the case at Swift Energy’s AWP Olmos Field in McMullen County, Texas, where the tight Olmos sand reservoir resisted commercial development long after its vast store of hydrocar-bons had been discovered. But during more than a decade of operation within the field, Swift

Source: Gas Research Institute

has been highly successful in its develop-ment of the field and has become recog-nized as a leader in tight-formation natural gas production.

With the experience it has gained in the AWP Olmos Field, as well as in other similar fields, Swift expects tight-formation operations to remain an important part of its long-term production program. Not only will the Company continue operations in the AWP Olmos Field for many years to come, it will also seek to apply its knowl-edge and expertise to other tight-formation fields, thereby helping to meet the nation’s increasing demands for natural gas as a vital energy source.

June 2000v

U.S. Natural Gas Productionfrom Tight Formations

(in trillion cubic feet)

Sources of U.S. Natural Gas Productionin Year 2000

Source: Gas Research Institute

The AWP Olmos Field—one of many tight-formation fields in the United States—has long been known to hold large quantities of hydrocarbons in its low-permeability, depletion-driv-en reservoir (the Olmos sand) at depths of 10,000 to 11,000 feet. However, the field presents severe challenges to operators, since commercial production of the natural gas and its ac-companying liquids is possible only if innovative applications of technology are used throughout the drilling, completion, and production processes.

Swift Energy’s operations in the AWP Olmos Field began with two initial acquisitions, one in 1988 and another in 1989, both consisting of interests in wells producing from an ap-proximately 4,900-acre lease-hold. With its 1989 purchase, Swift became the operator of the leasehold. Since then, the Com-pany has consistently increased

Introduction

Swift Energy Company’s performance in the AWP Olmos Field in McMullen County, Texas, is a prime example of how the Company’s technical teams apply old and new technologies in field operations to increase Swift’s oil and natural gas reserves and production.

As of December 31, 1999, Swift Energy was operating 460 wells in the AWP Olmos Field.

its interests—to the extent that it is now the largest operator in the field.

At year-end 1999, Swift’s interests in the AWP Field included 33,530 net acres on which the Company was operating 460 producing wells with average productive lives of 15 to 20 years. As one of the Company’s core areas of operation, the AWP Field accounted for 30.5% of Swift’s oil and natural gas production in 1999, 46% of its total year-end proved reserves, and 36% of its proved undeveloped reserves.

Swift’s development of the AWP Field is an ongoing success story. It is a story of how the Company’s technical teams through intensive studies and observations have increasingly under-stood the characteristics and variations of the Olmos sand and have applied appropriate tech-nologies to ensure economic operation of the field. It is also a story of how the Company has successfully negotiated favorable transportation, processing, and marketing agreements. And with many undeveloped sites yet to be drilled, it is a story that will continue for many years into the future.

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Swift Energy’s development of its AWP Olmos Field began in 1989 immediately after the Company assumed operation of 67 producing wells on the original 4,900-acre leasehold. As the

History of Swift’s AWP Olmos Field

new operator of the lease-hold, Swift’s immediate goal was to increase its production with a program of in-fill drill-ing, workovers on existing wells, and various facility and pipeline improvements, all to be carried out for profitability within a low price environ-ment.

Swift’s Early Operations (1989-1994)

Having previously worked with tight-sand formations in West Virginia, Swift was familiar with many of the op-erational techniques required for successful tight-sand exploitation. In particular, the Company had already had experience with the hydraulic fracturing techniques required to induce hydrocarbon flow into the well bores. A mas-sive and costly operation, the fracturing process used in the AWP Field at the time involved pumping a water-based gelled fluid and sand mixture down each well bore and out into the surrounding formation under pressures that were high enough to crack the formation. When the gell broke down and the fluid flowed back into the well and up to the surface, the sand was left behind, where it served as a proppant to hold the fractures open for subse-quent hydrocarbon flow.

The proper execution of

Tractor trailer loads of sand and water were delivered to a well site throughout a formation-fracturing process conducted in 1995.

Hydraulic FracturingThe AWP Olmos Field’s low-permeability, depletion-driven res-

ervoir releases only minimal quantities of its vast store of hydrocar-bons without the flow being artificially stimulated. In the procedure used, massive amounts of a fluid and sand mixture are pumped down the well bore and out into the formation under high enough pressures to fracture the formation, thereby creating pathways through which oil and gas can flow into the well. The fractures are propped open by sand left behind during flowback of the fluid.

With more than a decade of experience in hydraulic fracturing in the AWP Field, Swift’s engineers have repeatedly found innova-tive ways to cut costs while improving performance. A large part of their success lies in tailoring this technology for specific subsections of the field, using all available geological and fault data and apply-ing lessons learned from earlier fracture jobs.

Examples of modifications that Swift’s engineers make include adjusting the volume and type of proppant, altering the type and volume of fluid, changing the injection rates, and modifying flow-back procedures.

After several years of operation, Swift adopted a fracture ex-tension program in which the formation surrounding each well is fractured a second time in order to reach maximum production po-tential. In this program, the fracturing process has been significantly downsized, which, along with other refinements, has resulted in the total fracture costs per well being reduced by approximately 50%. At the same time, the economically recoverable reserves have been increased by an average of 290 million cubic feet of natural gas equivalent per well.

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the fracture process was vital to the success of an Olmos sand well. And with the costs of the process representing a large fraction of a well’s com-pletion costs, the Company soon initiated work on refin-ing its fracturing techniques. By the end of 1992, after drilling 16 successful wells in its in-fill program, Swift had succeeded in reducing the fracture job size by 50% and the costs by about $300,000 per well, primarily by switch-ing the proppant mate-rial to smaller volumes of a

resin-coated sand of higher strength. The in-fill program continued with three wells in 1993 and four wells in 1994, all completed as producers.

In the meantime, in 1992, Swift had again in-creased its interest in the leasehold and had assembled a technical team to work on several other fronts. The team began studying drain-age patterns within the field to better locate new wells, and it identified operating wells whose production could

be increased if they were subjected to a second hy-draulic fracture.

The team also focused on finding the most economi-cal techniques for increasing production from older wells whose declining pressures were allowing fluids (gas condensates) to build up in the well bores and inhibit the natural flow of hydrocarbons up to the surface. The most cost-effective technique, the team discovered, was to run velocity strings (1-1/4-

Swift was the first operator in the AWP Field to use 1-1/4-inch-diameter coiled tubing as “veloc-ity strings,” which increased well production at lower costs than those associated with other arti-ficial lifts.

Velocity StringsLiquid loading of natural

gas wells is a common occur-rence resulting from the buildup of natural gas condensates and other fluids in the well bores, ultimately blocking the flow of the natural gas to the surface.

Because of the low perme-ability of the Olmos sand, the liquid-loading problem hap-pens much earlier in the lives of wells in the AWP Field than it does in conventional fields where natural gas flow rates are higher.

Previous operators in the field attempted to overcome the liquid-loading problem with conventional mechanical lifts that were expensive to install and operate because of the deep well depths, the low pro-ductivity index of the wells, and other complications.

Seeking a more economical solution, Swift’s technical team recognized early on that the gas/liquid ratios encountered in the field made the wells strong candidates for artificial lift with “velocity strings” (1-1/4-inch-diameter coiled tubing) run down the wells. In 1989, Swift became the first operator in the

AWP Field to use velocity strings, which not only could be installed at 50% of the cost of mechanical lifts but also eliminated operating and repair costs.

Most of the wells showed im-mediate increases in both natural gas and condensate production as the smaller diameter of the coiled tubing forced the well bore fluids to flow through a reduced cross section, thereby increasing the flu-id velocity and its ability to entrain liquids and “unload.”

An added benefit of the velocity strings was corrosion protection. The strings can be used to pump anticorrosion chemicals down the annulus and back up the central tubing, providing corrosion protection without the well having to be shut down for treatment.

The only drawback in using coiled tubing is that its smaller diameter causes more pressure drop due to friction than con-ventional 2-3/8-in. or 2-7/8-in.-diameter tubing. However, Swift compensated for this reduction in flowing pressure by increas-ing compression in the field.

Swift’s technical team evaluated the tradeoff of flow-rate restriction caused by coiled tubing friction versus flow-rate restriction caused by liquid loading. This analysis included conducting flowing bottom-hole pressure surveys on 10 wells being considered for coiled tubing. The resulting engineering analysis provided solid evidence of the increase in performance and reduction in costs achieved by using ve-locity strings to maximize pro-duction.

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in. coiled tubing) from the bottom of the hole to the surface. The smaller diameter tubing increased the velocity of the produced gas, which helped to carry the produced liquids to the surface.

By installing the velocity strings—the first operator in the field to do so—Swift cut capital costs over 50% com-pared with the costs of other artificial lifts.

Confident about the team’s increased understand-ing of the AWP Olmos Field and its successes in economi-cally overcoming obstacles, the Company was convinced that it should expand its op-erations and focus on making the field one of its core areas of operation. Thus in 1994, Swift acquired an additional 8,830-acre leasehold posi-tion immediately south of the original leasehold. At year-end, the combined reserves of the original leasehold and the new one totaled 38 bil-lion cubic feet of natural gas equivalent (Bcfe).

Expansion into a New Area (1995)

In 1995, Swift drilled nine more successful wells in its in-fill program on the original 4,900-acre leasehold. In ad-dition, in the second quarter of the year, it launched a pro-gram of drilling on the new undeveloped acreage.

By this time the suc-cess of velocity strings as lift devices in multiple wells had made it obvious that most

of the AWP wells would eventually be fitted with the 1-1/4-inch-diameter coiled tubing and that mechanical lift systems requiring larger hole diameters would not be necessary. It followed that savings in drilling and completion costs in the new area could be realized if the size of the drilled holes was reduced.

Following a study by Swift’s technical team to determine just how small the diameter of the drilled holes could be without adversely affecting initial production, the Company adopted “slim-hole” drilling techniques in which the diameter of the drilled hole was reduced by 2-3/8 inches at the surface (down to 9-7/8 inches) and by 1-3/8 inches at reser-voir depths (down to 6-1/2 inches). This change reduced footage drilling costs by ap-proximately 15%, or about $18,500 per well.

The smaller hole also facilitated other cost savings. For example, the casing used in the hole was small enough for wells to be completed without tubing first being run. Also, the smaller cas-ing resulted in a savings of $25,000 per well on tubular costs and $1,500 per well in drilling mud costs.

In addition, Swift imple-mented single-stage cement-ing of the well instead of two-stage cementing that required a stage tool and a completion rig. This saved about $9,000 per well.

Altogether, the conver-sion to slim-hole drilling reduced drilling costs by approximately $54,000 per well, or 10 to 15%.

Soon after the drilling

Swift’s conversion to a slim-hole drilling technol-ogy using small drilling bits significantly reduced drill-ing and completion costs.

By converting to a slim-hole drilling technology, Swift Energy reduced drill-ing and completion costs through decreased drilling time, lower drilling mud quantities, less expensive tubulars, and single-stage cementing (see sidebar on page 7).

Previous operators in the field had used standard 9-5/8-inch-diameter surface casing and 5-1/2-inch pro-duction casing, which was necessary to make room for the standard mechani-cal lifts that were eventually installed in most wells. Since Swift used velocity strings for artificial lift, it was possible to drill a narrower-diameter well bore.

As a result, the Com-pany could use a 7-5/8-inch surface casing and a 3-1/2-inch production casing. With the smaller hole, the flow velocity did not decrease so rapidly and the installation of the velocity strings could be delayed.

Slim-Hole Drilling

4

Swift’s operations engineer Paul Mladenka (right) uses re-mote monitoring technology in the Company’s Houston of-fice to supervise a hydraulic fracturing job taking place in the AWP Field 250 miles away.

in the new area had begun, however, Swift discovered that the fracturing process it had refined for the original lease-hold did not always work in the new area. With few other wells having been drilled in the near vicinity, the virgin pressure of the Olmos sand reservoir still existed and was essentially the same as the pressures in the shale layers above and below the reservoir. This precluded the use of pres-sure differentials to help keep the induced vertical fractures within the productive zone. Also, the reservoir was even less permeable than that in the original leasehold, necessitat-ing that the fracture jobs be greatly increased (by as much as 400%) to accomplish a res-ervoir penetration comparable to that in the original lease-hold. Because these fracture jobs were much more costly, the Company’s technical team once again began to focus on fracture design.

In order to gain more information about the effects of variations introduced in the fracture process, measure-ments of the bottom-hole pressure, which is considered to be “the heart beat of a frac job,” were made during the treatment process on some of the early wells. “Dead strings” of 1-1/4-inch coiled tubing were run into the well bore and filled with water. As the fracturing fluid was pumped down the annulus between the tubing and casing, the tubing pressure was monitored. With an accurate downhole pres-sure, the engineer overseeing

Remote Monitoring of FracturingUsing computer and telecommunications networks, Swift

Energy developed a system that allows Swift engineers to moni-tor an approximately 18-hour fracture stimulation process in real time from their offices at the Company’s headquarters in Houston, located 250 miles away from the field. Variables such as treating pressures, pump rates, and slurry concentrations are closely moni-tored on three computer screens, and engineers routinely make job design modifications while a fracture stimulation process is under way.

This technology permits the engineer to conveniently monitor successive fracture jobs without frequent costly trips to the field.

the job could filter out the effects on pressure read-ings of variations introduced throughout the process. Effects not understood could mean that the fractures were going out of zone (into the shale layers above or below the reservoir), communicat-ing with fractures of other wells, starting to screen out, etc.—all of which would prompt the engineer to make changes during the job in progress.

After these effects were better understood, the Com-pany concentrated in four different areas:

(1) Reducing the overall job size and costs by using smaller amounts of fluid and sand and by substituting cheaper ordinary sand (Ot-tawa sand) for some of the resin-coated sand.

(2) Using less-viscous fluid, which would help con-trol the growth of the vertical fracture height.

(3) Slowing the injection rate, also to reduce vertical height growth.

(4) Implementing imme-diate fracture fluid flowback to induce fracture closure

5

and minimize the settling of the proppant in the bottom of the fracture.

With the renewed empha-sis on the fracturing of the wells and the increased num-ber of wells being drilled, the operations engineer monitor-ing and directing each frac-ture job was forced to spend inordinate amounts of travel time between the field and the Company’s Houston head-quarters. In order to eliminate his lost time and the related costs, and also to enable him to avoid field distractions and concentrate on the downhole dynamics, Swift installed an innovative computer and tele-communications system that would allow remote monitor-ing of the jobs from real-time plots of critical data displayed on computer screens in a headquarters office.

As drilling successes ac-crued in the new area, the Company once again ex-panded its acreage position in the field, which by year-end 1995 had grown to 17,000 net acres. To expedite the pro-gram, Swift deployed a sec-ond drilling rig, each requiring 12 to 14 days to reach the target formation. By year-end 1995, a total of 32 wells had been placed in production in the new area of the field.

Based on the production data for all of Swift’s wells, plus public information on the production histories of other wells in the vicinity, Swift’s geologists and reser-voir engineers determined

Single-Stage CementingThe purpose of cementing a well is twofold: (1) to seal off

non-reservoir fluids that might otherwise enter the hole, and (2) to prevent contamination of the earth’s fresh-water zone with hy-drocarbons and other fluids. Typically, the cement fills the annulus between the pipe casing and the side of the drilled hole.

Traditionally, well cementing has been done in two stages. First, the bottom of the hole is sealed off with concrete pumped down through the center of the casing and then back up the annulus sur-rounding the casing to the desired height. Subsequent perforations through the casing and cement allow the natural gas and gas fluids to flow from the reservoir into the hole for production while other fluids that might otherwise enter the annulus are excluded.

Second, a “stage tool” sleeve is set in the hole from the ground surface down to a depth just below the fresh-water zone (at approx-imately 5,000 feet). With this tool in place, cement is again pumped down the hole and diverted through ports into the annulus in the region of the fresh-water zone, thus sealing off the zone.

Once the cement is in place in this two-stage procedure, a completion rig must be brought in to drill out the cement left in the stage tool sleeve, as well as to open up the bottom of the sleeve and generally clean out the hole.

In single-stage cementing, which is the procedure adopted in the AWP Field, the annulus is filled with cement over the full depth of the hole, which eliminates the need for the stage tool and the completion rig, more than offsetting the increased costs for the ad-ditional cement.

The main challenge in perfecting the single-stage cementing procedure was to achieve full circulation of the cement and to en-sure that the fresh-water zone was indeed isolated. To achieve this, the engineers adjusted the cement pump rates and other variants such as slurry designs.

6

The geographic concentration of AWP wells allows Swift to use a central-ized gathering system, which reduces expens-es.

that the Company’s proven net reserves in the AWP Field at year-end 1995 were equal to 118.1 Bcfe. Of this volume, 91 Bcfe was in the new area in which 68% of the reserves were still undeveloped. This analysis was confirmed by an outside consultant, H. J. Gruy and Associates, Inc.

Further Expansion and Infrastructure Upgrades (1996)

During 1996, Swift Energy more than doubled its total AWP acreage position to ap-proximately 35,000 net acres and engaged additional drilling rigs, with a total of eight rigs operating simultaneously at year-end. As a result, 124 wells were drilled during the year with 120 successfully com-pleted as producers, including one exploratory well. Overall, Swift’s drilling success rate in the field for the year was 97%.

A continuing analysis of proven reserves by Swift’s technical team revealed that by the end of 1996 the Com-pany’s proved reserves for the new area had increased 86% to 169 Bcfe. Of this amount, 47% was associated with producing wells. Annual production from the new area increased 984% from the pre-vious year to 8.858 Bcfe, while annual revenues rose 1,261% to $24.4 million.

With the original leasehold included, the AWP Field held 200.4 Bcfe of the Company’s total year-end reserves. It also contributed 11.1 Bcfe (or 57%) of the Company’s total

Gathering System

The infrastructure for gathering and transporting natural gas in the new area of the AWP Field is designed to allow maximum flex-ibility as Company operations expand. The system is comprised of a network of strategically located flow stations that are connected to a central facility where natural gas, oil, and water from all wells are separated at one location. This greatly reduces gathering expenses (without adversely affecting deliverability) by eliminating the need for individual well facilities such as tank batteries.

The end result is a highly adaptable natural gas gathering system that achieves the following:

Geographic expansion. The system can easily be expanded to include new geographic areas as they are developed, and it was built with future expansion in mind.

Well productivity. The design maximizes well productivity in all stages of the field’s development.

Size flexibility. The system performs competently whether a small number or a large number of wells are connected.

Cost efficiency. The design is cost efficient in terms of both capital expense and operating expense.

Pressure options. The system uses both high-pressure and low-pressure gas flow systems, and, if needed, the high-pressure system can be used to deliver low-pressure gas to minimize poten-tial bottlenecks and line losses across the low-pressure system or to ease the load on the main compressor.

By year-end 1999, Swift’s natural gas gathering system in the AWP Field had grown to include 20 flow stations/tank batteries and had 4500 horsepower of compression. Swift’s technical person-nel continuously monitors conditions in an effort to maximize field efficiency through rapid identification and resolution of potential problems.

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Valero SalesCompressorOil StorageFlow Station

Gathering SystemAs of 7/31/2000

1996 production and $29.8 million (or 56%) of its total oil and gas sales.

As production from the new area continued to increase, an internal infra-structure for gathering and transporting the natural gas and associated liquids became critical to the overall economic success of the field.

A gathering system for the original leasehold had long been in place, and the lease-hold’s production, excluding an amount designated for a volumetric production pay-ment agreement, had always been sold by Swift to a single customer. For the new area, however, the infrastructure was only partially developed and needed immediate atten-tion.

To eliminate the need and expense for individual well facilities such as tank batter-ies, the Company designed an evolving network of strategi-cally located flow stations, all connected to a central facility via both high-pressure and low-pressure gas flow sys-tems, along with liquid lines to deliver condensate. Each flow station collected mul-tiple well streams, which were combined and routed to a separator, from which gas and liquid streams were sent to the central facility. As the develop-ment of the area proceeded, flow stations could be added and new wells connected to the system. At year-end 1996, the gathering system included 13 flow stations and 147 miles of flow lines.

In addition, automated electronic flow meters were placed throughout the field to enhance data retrieval capa-bilities and minimize the cost of manpower in the field. The meters were linked by radio to the field office and

ultimately to Swift’s Houston headquarters through a dedi-cated phone line. Through these links, each meter could be remotely monitored in real time, alarms could be set on critical points within the system, and individual wells

Solar-powered flow meters, which send production data via radio transmission to a central computer system, are part of Swift’s remote production monitor-ing system.

Remote Monitoring of Production

Even though the number of wells in the new area of the AWP Field have greatly increased, the Company has lowered field op-erating costs by re-motely monitoring natural gas produc-tion. This system, which eliminated the need for field employees to physi-cally check every well every day, uses solar-powered flow meters that send production data via radio transmission to a central com-puter system in the field office. From there, the informa-tion can be transmitted over a dedicated telephone line to Com-pany headquarters in Houston.

As of year-end 1999, Swift had more than 300 wells connected to this monitoring system, as well as numerous compressors and sales points.

In addition to reducing manpower requirements, benefits of this technology include improvements in the accuracy and accessibility of the production data. The system also allows smoother produc-tion 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 velocity strings significantly delay liquid-loading problems, an eventual decline in production is unavoidable as the formation pressure decreases over time. Periodically closing aged wells builds up the pressure needed to overcome liquid loading and allow production to continue. 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 hydraulic fracturing to determine if the fracture is affecting nearby wells.

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could be opened and closed from the office. As a result, the Company was able to manage the increasing pro-duction without adding field personnel.

To better market its in-creasing production from the new area, the Company en-tered into an agreement with Valero Energy Corporation (subsequently purchased by PG&E-Texas) for the trans-portation and processing of up to 75 million cubic feet of natural gas per day. Valero laid 13 miles of a 12-inch-diameter line from the company’s processing plant in order to tap into Swift’s central facility, and later into other points across the field.

Under the terms of Swift’s agreement with Valero, Swift itself was to market the gas that Valero processed for the Company. However, a baseline amount was first to be sold to Valero, which had its own pipeline connected to a hub in the southern tip of Texas.

From the processing plant Swift had access to 11 major interstate and intra-state pipelines extending across the eastern portion of the United States. With this access it became possible for the Company to sell directly to end users such as manu-facturers, power plants, and utilities without the necessity of going through a middle man. Eventually, the Com-pany also was able to sell to customers, primarily refiner-

ies, along the Corpus Christi and Houston ship channel via the Valero pipeline.

As the intensity of the drilling program increased throughout the year, the frac-ture job sizes still remained

much larger than those on the original leasehold. With continued adjustments that considered the variation of the reservoir permeability across the field and allowed each fracture job to be tai-lored to the individual well,

Following Swift’s negotiation of an agreement with Valero Energy Corporation to transport and process its natural gas production, Valero built a 13-mile, 12-inch-diameter pipe-line to its processing plant.

Transportation and Processing AgreementSwift negotiated a natural gas transportation and processing

agreement in 1996 with Valero Energy Corporation (now PG&E-Texas). As part of the agreement, Valero constructed 13 miles of a 12-inch-diameter pipeline from Swift’s central facility to Valero’s processing plant, which delivers the gas to 11 interstate and intra-state pipelines (see page 10).

The immediate impact of this action lowered the sales line pres-sure by approximately 200 psi, which increased total field deliver-ability because of the inverse relationship between line pressure and deliverability.

A secondary benefit was Valero’s installation of additional sales taps into the line across the central and southern portions of Swift’s acreage. These taps can be used to redirect portions of the gas flow within the field and minimize the line pressure within the system.

Swift’s agreement with Valero has a “keep whole” provision, which allows Swift to either take its share of the liquids extracted from its natural gas wellstream or to be paid for the shrinkage gas at the prevailing downstream market if that price is higher. To date, the prices received for the processed liquids have proven to be more profitable to Swift than the prices for gas shrinkage.

9

the job sizes were somewhat reduced. Still, their magni-tude was apparent by the volumes of materials used. By the end of 1996, approxi-mately 171 million pounds of sand had been pumped into wells drilled in the new areas (enough to fill 1,053 rail cars).

Sustained Drilling Program (1997)

During 1997, the Com-pany increased its total lease-hold acreage in the AWP Field to 40,568 net acres* and drilled an additional 142 development wells. Of these, 137 were producers, yield-ing a success rate of 95.2%. Consistent with the design of the gathering system, three flow stations were added to the field to accommodate the expansion of the developed areas.

With the added wells, Swift’s 1997 production from the AWP Field reached 15.5 Bcfe, and the proven reserves associated with the field had risen to 267 Bcfe, 62.2% of which were developed.

As Swift’s refinements of the fracture process continued during the year, the fracture costs in some areas were reduced by as much as 50%. Concern still remained, how-ever, that most of the fractures had not been as efficient as was needed to expose large portions of the surrounding reservoir to the lower well

*By year-end 1999, Swift had reduced its net acreage to 33,530 acres.

pressures. As a result, a full-fledged “fracture extension” program, in which wells were subjected to second fractures, was increasingly being con-sidered. Second fractures had already been applied with success to 39 wells from 1995 through 1997, and by year-end 1997, 40 wells had been identified as candidates for fracture extensions in 1998.

A Shift of Emphasis (1998)

As it turned out, the precipitous declines in oil and natural gas prices during 1998 caused the Company to place even more emphasis on its fracture extension program than it had planned. Because

of high drilling costs and low product prices, Swift’s 1998 drilling program in the AWP Field was limited to 36 wells (31 of which were successful), and the fracture extension program was increased to 103 wells. At year-end, an analysis of 83 wells with at least two months of production after the second fracture indicated that the average per-well increase in production for the 103 wells in the 1998 fracture extension program was approximately 290,000 cubic feet of natural gas equivalent per day (290 Mcfe per day).

As experience was gained in the fracture extension pro-gram, its effectiveness became even more apparent. Because

Swift Energy has access to interstate and intrastate pipe-lines from its AWP Olmos Field.

Pipeline AccessFrom the Valero (now PG&E-Texas) processing plant, Swift

Energy has access to 11 major interstate and intrastate pipelines that reach nearly every major U.S. market in the Northeast and Midwest. In addition, the Company has access to the Corpus Christi and Houston ship channel via a Valero pipeline. This ac-cess to numerous pipelines has allowed the Company to market directly to end users, thereby improving its profitability from sales.

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the first fractures reduced the pressure of the depletion-driven Olmos formation, the second fractures were more ef-ficient in extending the cracks deeper into the reservoir. Also, with the pressure of the Olmos formation then less than the pressures of the shale layers above and below the forma-tion, the second fractures were more likely to stay within the target zone and not protrude into the nonproductive shale.

It followed that a two-phase fracture process should be considered as the routine procedure for all newly drilled

wells and not just for selected under-producing wells. In the two-phase process, each well drilled would first receive a “sacrificial” fracture job to knock the pressure down and initiate the flow of hydro-carbons. Then, three to six months later the well would receive a second, possibly larger, fracture job, the design of which would benefit from data gathered after the first job. The synergy of the two fractures would result in deep-er penetration of the reservoir surrounding each well with an accompanying increase in production.

The next obvious chal-lenge was to minimize the costs of a two-fracture pro-cedure by determining how much the fracture operations, especially the first one, could be downsized without com-promising the results. As a first step, the fracture jobs were designed to use only water as the fluid (as opposed to the earlier recipe of gelled fluid) and to use smaller volumes of the fluid. Next, the mixtures of proppant materials (the Ot-tawa sand and coated sand) were carefully tailored for each well, with the volumes minimized insofar as was

Increased Recovery from Fracture Extension ProgramThe fracture extension program in the AWP Olmos Field has significantly increased the economically

recoverable reserves per well.

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Before Fracture Extension After Fracture Extension

feasible. As a result, the cost of each fracture job performed in 1998 was less than one-half the cost of a fracture job performed in the new area in 1995.

With the increased produc-tion from the fracture exten-sion program, plus the addi-tional production from the 31 successful wells drilled during the year, the Company’s AWP Field production level for 1998 was maintained at 15.5 Bcfe. However, by year-end Swift’s proved reserves in the AWP Field had declined to 223.9 Bcfe, a much lower

volume than would have been expected after the year’s pro-duction was subtracted.

The difference was ex-plained by the necessity during 1998 for downward adjustments in the reserves due to accounting rules that required that the current pric-ing be applied to long-term production projections. Thus, reserves that the Company knew existed in the AWP Field but that could not be produced economically in the future at the prevailing low prices had to be temporarily discounted.

Focus on Fracture Exten-sions, Velocity Strings (1999)

With the oil and conden-sate prices that Swift Energy was receiving at the beginning of 1999 dipping below $11 per barrel and natural gas prices staying well below $2 per thousand cubic feet, the Com-pany had little incentive for additional drilling in the AWP Field in early 1999. Instead, except for one well drilled dur-ing the first quarter, it focused on increasing production from the existing wells by continuing its fracture extension program.

Vapors with high energy content are captured at Swift’s AWP gathering facilities and compressed into the sales pipeline.

Environmental ProgramSwift’s environmental and safety efforts in the AWP

Field have had the added benefit of increasing economic returns from the field.

One example is the vapor-recovery system that Swift installed to capture natural gas vapors containing vola-tile organic compounds (VOC), which are considered to be carcinogenic air pollutants if released into the atmo-sphere but are a desired energy product if captured.

These vapors are released during production as the liquids move from the higher-pressure reservoir into lower-pressure heater-treater separators and into storage tanks. After being captured, the vapors are then com-pressed into the natural gas pipeline and sold.

The economic benefit of the vapor-recovery sys-tem is twofold. First, the captured vapors comprise 1% of Swift’s natural gas production from this field, a sig-nificant volume that otherwise would be lost into the atmosphere. Second, these vapors have a high energy content that is almost double that of most of the natural gas produced from this field and thus command a higher sales price.

From an environmental and safety standpoint, the capture of these vapors reduces both air pollution and the risk of fire that accompanies VOC emissions.

Another environmental improvement Swift has undertaken in the AWP Field is installing catalytic con-verters on large natural gas compressors. The catalytic converters reduce nitrogen oxide emitted from the internal combustion engines used to run the compressors, similar to the way that an automobile’s catalytic converter reduces its emissions. Nitrogen oxide is an air pollutant that combines with other compounds to create ground-level ozone.

Taken together, Swift’s environmental improvements in the AWP Field have reduced the air pollution emissions at its facilities to well below the limits mandated by state and federal regulations. Because of this, the Company does not have to buy air permits from the regulating agencies, which is a savings of time, money, and extensive paperwork.

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In addition, it accelerated its installation of velocity strings.

During the year, 84 wells outside the original lease-hold of the AWP Field were subjected to second frac-tures, including some of the 31 wells drilled in 1998 that had received smaller initial fractures. As the fracture extension program contin-ued, Swift’s team gradu-ally reduced the size of each fracture job as much as it dared, subsequently analyz-ing the results for each well. By year-end, the amount of sand used had been reduced to approximately 250,000 pounds per fracture job.

Also, since Swift had converted to using only water as its fluid, the purity of the water was not critical. In the earlier fracture jobs, when chemicals were added to cause the water to gel (and better carry the sand into the fractures), it was important that the water not include impurities that would be incompatible with the chemi-cals. As a result, the purchase of large quantities of treated water had comprised a large fraction of the fracture costs.

During 1999 the truck-loads of treated water were replaced with well water from the field. The water was pumped through lines laid across the field to fill ten 500-barrel “frac” tanks.

With these changes and other innovations, frac-ture jobs that initially cost

$250,000 per well in the new areas of the field were reduced to approximately $130,000 per well (with the two fractures per well each averaging about $65,000). Moreover, the results were much more satisfactory.

The daily increases in production resulting from the 1999 fracture extension program averaged between 175,000 and 225,000 cubic feet of natural gas equivalent per well (between 175 and 225 Mcfe per well), while the increase in the total recov-erable reserves averaged 290,000,000 cubic feet of natural gas equivalent per well (290 MMcfe per well).

Other production increas-es of 25 to 30 Mcfe per well per day were gained by the installation of velocity strings in over 50 wells.

In another cost-cutting move, a savings of $75,000 per month was effected when the Company drilled a frac water disposal well approxi-mately 5 miles south of its southernmost production area. After converting an existing pipeline to transport the water produced from the wells, Swift began pumping 90% of the frac water to the disposal well instead of pay-ing $1 per barrel to have it trucked out.

Other infrastructure im-provements included the ad-dition of more flow stations, with a total of 20 stations in

operation by year-end (out-side the original leasehold).

While these programs were under way, a dramatic recovery in oil and gas prices began to occur during the last half of 1999, encourag-ing the Company to resume some drilling during the fourth quarter. By December 31, six wells had been drilled with five successful comple-tions.

The resumption of the drilling program happened too late, however, to over-come the impact of its curtail-ment during the previous two years. Production from the field during 1999 fell to 13.1 Bcfe compared to 15.5 Bcfe in the previous year.

The year-end reserves for the field were rated at 207.7 Bcfe, comprising 45.7% of Swift’s total reserves. Of this amount, 83.6 Bcfe (or 40.3%) was still undevel-oped.

The Year 2000 and Beyond

When Swift Energy entered the year 2000, it had already identified 141 proven undeveloped locations for future drilling in the AWP Ol-mos Field. At the same time, the resurgence in oil prices and concomitant increases in natural gas prices appeared to have created a pro-drilling environment.

With the duration of this

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environment uncertain, how-ever, the Company chose to continue its conservative op-erational approach through most if not all of the year 2000, with plans to drill only 12 wells in the AWP Field during the year.

It also planned to con-tinue its fracture extension program with 75 second frac-tures projected for the year.

While it was anticipated that the reservoir pressures would decline as the drilling program increasingly in-

cluded in-fill drilling, the last three wells drilled in 1999 all encountered virgin pressures. Thus further cost reductions in the fracture jobs associ-ated with decreased reservoir pressures were still to be pursued.

The pace of the AWP drilling program in the year 2000 and beyond will ulti-mately be determined by the price environment and by the choices Swift makes on investing its resources, with the AWP Field competing with the Company’s other

core areas. Nevertheless, it is clear that developmental drilling will continue in the field for several years, and that production from the field will be contributing to Swift’s earnings at least into the next two decades.

It is also clear that Swift’s technical team will utilize the considerable knowledge and experience it continues to gain in the field to ensure that its operation remains economically viable in an unpredictable and often fluc-tuating price environment.

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